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 September 30, 2001
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 November 2, 2001
----------------------------- -------------------------------
Common Stock, $.005 Par Value 63,080,322
-1-
PART I
FINANCIAL INFORMATION
-2-
ITEM 1. FINANCIAL STATEMENTS
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except shares
and per share amounts)
(Unaudited)
ASSETS
------
September 30, December 31,
2001 2000
------------- ------------
CURRENT ASSETS:
Cash and cash equivalents .................................................... $ 14,012 $ 19,506
Accounts receivable -
Oil and gas sales .......................................................... 88,674 146,770
Joint operations ........................................................... 18,653 6,267
Derivative financial instruments receivable .................................. 5,746 -
Prepaids and other current assets ............................................ 32,570 13,946
------------- ------------
Total current assets .................................................. 159,655 186,489
------------- ------------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method ............................ 2,516,039 1,734,003
Oil and gas gathering systems and plants ..................................... 28,668 19,252
Other ........................................................................ 24,182 19,636
------------- ------------
2,568,889 1,772,891
Less: Accumulated depreciation, depletion and amortization ................... 794,796 667,837
------------- ------------
1,774,093 1,105,054
------------- ------------
GOODWILL, net of amortization .................................................. 166,335 -
------------- ------------
OTHER ASSETS, net .............................................................. 61,141 46,854
------------- ------------
$ 2,161,224 $ 1,338,397
============= ============
See notes to unaudited consolidated financial statements.
-3-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
LIABILITIES AND STOCKHOLDERS' EQUITY
September 30, December 31,
2001 2000
------------- ------------
CURRENT LIABILITIES:
Revenue payable .............................................................. $ 37,065 $ 60,519
Accounts payable - trade ..................................................... 56,232 43,225
Current income taxes payable ................................................. 14,217 43,187
Short-term revolving debt .................................................... 10,917 3,400
Other payables and accrued liabilities ....................................... 75,160 61,961
------------- ------------
Total current liabilities ................................................. 193,591 212,292
------------- ------------
LONG-TERM DEBT ................................................................. 1,016,344 464,229
------------- ------------
DEFERRED INCOME TAXES .......................................................... 215,449 33,252
------------- ------------
OTHER LONG-TERM LIABILITIES .................................................... 2,376 3,767
------------- ------------
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,
63,080,322 and 62,801,416 shares issued and
outstanding, respectively ................................................. 315 314
Capital in excess of par value ............................................... 323,322 319,893
Retained earnings ............................................................ 426,303 303,449
Accumulated other comprehensive income (loss) ................................ (14,531) 1,201
------------- ------------
735,409 624,857
Less: Unamortized cost of restricted stock awards ............................ 1,945 -
------------- ------------
733,464 624,857
------------- ------------
$ 2,161,224 $ 1,338,397
============= ============
See notes to unaudited consolidated financial statements.
-4-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share amounts)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2001 2000 2001 2000
--------- --------- --------- ---------
(Restated) (Restated)
REVENUES:
Oil and gas sales ................................................ $ 173,227 $ 185,546 $ 588,610 $ 476,334
Gas marketing .................................................... 20,481 38,988 115,295 82,868
Oil and gas gathering and processing ............................. 794 5,529 15,100 13,223
Gain (loss) on disposition of assets ............................. - (805) 24 (1,188)
Other income (expense) ........................................... (679) 722 2,198 (22,600)
--------- --------- --------- ---------
193,823 229,980 721,227 548,637
--------- --------- --------- ---------
COSTS AND EXPENSES:
Lease operating, including production taxes ...................... 58,314 41,926 159,062 116,800
Exploration costs ................................................ 9,561 8,949 15,253 12,330
Gas marketing .................................................... 20,540 37,482 112,163 79,409
Oil and gas gathering and processing ............................. 1,299 5,019 15,776 11,337
General and administrative ....................................... 13,080 9,413 37,173 28,650
Depreciation, depletion and amortization ......................... 48,072 26,197 116,060 71,633
Impairment of oil and gas properties ............................. 10,706 - 10,706 -
Amortization of goodwill ......................................... 4,417 - 7,191 -
Interest ......................................................... 19,867 11,609 46,658 36,948
--------- --------- --------- ---------
185,856 140,595 520,042 357,107
--------- --------- --------- ---------
Income before income taxes and cumulative effect of change in
accounting principle ........................................... 7,967 89,385 201,185 191,530
PROVISION (BENEFIT) FOR INCOME TAXES:
Current .......................................................... 6,370 25,902 56,565 49,078
Deferred ......................................................... (4,645) 4,934 15,461 17,138
--------- --------- --------- ---------
1,725 30,836 72,026 66,216
--------- --------- --------- ---------
Income before cumulative effect of change in
accounting principle ........................................... 6,242 58,549 129,159 125,314
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE, net of taxes of $644 .................................. - - - (1,422)
--------- --------- --------- ---------
NET INCOME ......................................................... $ 6,242 $ 58,549 $ 129,159 $ 123,892
========= ========= ========= =========
BASIC INCOME PER SHARE:
Income before cumulative effect of change in
accounting principle ........................................... $ 0.10 $ 0.93 $ 2.05 $ 2.00
Cumulative effect of change in accounting principle .............. - - - (.02)
--------- --------- --------- ---------
Net income ....................................................... $ 0.10 $ 0.93 $ 2.05 $ 1.98
========= ========= ========= =========
DILUTED INCOME PER SHARE:
Income before cumulative effect of change in
accounting principle ........................................... $ 0.10 $ 0.92 $ 2.02 $ 1.96
Cumulative effect of change in accounting principle .............. - - - (.02)
--------- --------- --------- ---------
Net income ....................................................... $ 0.10 $ 0.92 $ 2.02 $ 1.94
========= ========= ========= =========
Weighted average common shares outstanding:
Basic ............................................................ 63,080 62,770 63,003 62,592
========= ========= ========= =========
Diluted .......................................................... 64,068 63,956 64,092 63,892
========= ========= ========= =========
See notes to unaudited consolidated financial statements.
-5-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
AND COMPREHENSIVE INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2001
(In thousands)
(Unaudited)
Capital Unamortized Accumulated
Common Stock In Excess Restricted Other
---------------- of Par Stock Retained Comprehensive
Shares Amount Value Awards Earnings Income Total
------ ------ --------- ----------- --------- ------------- --------
Balance at December 31, 2000 ........... 62,801 $ 314 $ 319,893 $ - $ 303,449 $ 1,201 $624,857
Cumulative effect of adoption of
SFAS No. 133 ......................... - - - - - 14,915 14,915
Comprehensive income:
Net income ........................... - - - - 129,159 - 129,159
Foreign currency translation
adjustment ......................... - - - - - (20,311) (20,311)
Change in value of
derivatives ........................ - - - - - (10,336) (10,336)
--------
Total comprehensive income ........... 98,512
--------
Exercise of stock options and
resulting tax effects ................ 169 1 1,215 - - - 1,216
Issuance of restricted stock ........... 110 - 2,214 (2,214) - - -
Amortization of restricted
stock awards ......................... - - - 269 - - 269
Cash dividends declared
($.10 per share) ..................... - - - - (6,305) - (6,305)
------ ------ ---------- ------------ --------- ------------- --------
Balance at September 30, 2001 .......... 63,080 $ 315 $ 323,322 $ (1,945) $ 426,303 $ (14,531) $733,464
====== ====== ========== ============ ========= ============= ========
See notes to unaudited consolidated financial statements.
-6-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended
September 30,
------------------------------
2001 2000
------------- ------------
(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ...................................................................... $ 129,159 $ 123,892
Adjustments to reconcile net income to cash provided by operating activities,
net of acquisitions-
Depreciation, depletion and amortization .................................... 116,060 71,633
Impairment of oil and gas properties ........................................ 10,706 -
Amortization of goodwill .................................................... 7,191 -
Exploration costs ......................................................... 15,253 12,330
Provision for deferred income taxes ....................................... 15,461 17,138
Other adjustments ......................................................... 714 1,188
Cumulative effect of change in accounting principle ......................... - 1,422
------------- ------------
294,544 227,603
Decrease (increase) in receivables .............................................. 62,026 (44,272)
Increase (decrease) in payables and accrued liabilities ......................... (67,529) 88,555
Other ........................................................................... (21,549) 3,971
------------- ------------
Cash provided by operating activities ................................... 267,492 275,857
------------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures -
Oil and gas properties ........................................................ (214,479) (155,410)
Gathering systems and other ................................................... (3,971) (1,827)
Proceeds from sale of oil and gas properties .................................... 24 863
Purchase of companies, net of cash acquired ..................................... (478,417) -
Other ........................................................................... (9,155) (2,767)
------------- ------------
Cash used by investing activities ....................................... (705,998) (159,141)
------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Issuance of common stock ........................................................ 1,216 3,493
Issuance of 7 7/8% Senior Subordinated Notes due 2011 ........................... 199,930 -
Advances on revolving credit facility and other borrowings ...................... 719,090 35,920
Payments on revolving credit facility and other borrowings ...................... (480,880) (179,632)
Dividends paid .................................................................. (5,981) (5,003)
------------- ------------
Cash provided (used) by financing activities ............................ 433,375 (145,222)
------------- ------------
Effect of exchange rate changes on cash ........................................... (363) -
------------- ------------
Net decrease in cash and cash equivalents ......................................... (5,494) (28,506)
Cash and cash equivalents, beginning of period .................................... 19,506 42,687
------------- ------------
Cash and cash equivalents, end of period .......................................... $ 14,012 $ 14,181
============= ============
See notes to unaudited consolidated financial statements.
-7-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
September 30, 2001 and 2000
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 interests in various joint ventures (collectively, the
"Company"). Management believes that all material adjustments (consisting of
only normal recurring adjustments) necessary for a fair presentation have been
made. All significant intercompany accounts and transactions have been
eliminated in consolidation. Certain 2000 amounts have been reclassified to
conform with the 2001 presentation. These reclassifications have no impact on
net income.
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 2000 audited financial statements and related notes included in the
Company's 2000 Annual Report on Form 10-K, Item 8. Financial Statements and
Supplementary Data.
2. SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
Under the successful efforts method of accounting, the Company capitalizes
all costs related to property acquisitions and successful exploratory wells, all
development costs and the costs of support equipment and facilities. All costs
related to unsuccessful exploratory wells are expensed when such wells are
determined to be non-productive; other exploration costs, including geological
and geophysical costs, are expensed as incurred. The Company recognizes gains or
losses on the sale of properties on a field basis.
Unproved leasehold costs are capitalized and are reviewed periodically for
impairment. Costs related to impaired prospects are charged to expense. An
impairment expense could result if oil and gas prices decline in the future as
it may not be economic to develop some of these unproved prospects.
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.
Estimated abandonment costs, net of salvage value, are included in the
depreciation and depletion calculation.
-8-
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, based on the Company's expectations of future
oil and gas prices and costs, consistent with the method used for acquisition
evaluations.
The Company recorded a $9.1 million impairment charge during the third
quarter of 2001 related to certain domestic properties that were held for sale
during the fourth quarter of 2001. The impact of these properties on the results
from operations in the accompanying income statements is immaterial. The Company
also recorded a $1.6 million impairment charge during the third quarter of 2001
related to certain Canadian producing oil and gas properties. No other
impairment charges were required during 2001. No impairment provision related to
proved oil and gas properties was required for the first nine months or the
third quarter of 2000.
Prior to 2001, the Company considered only proved oil and gas reserves in
determining fair value. However, with the December 2000 Cometra Acquisition and,
more significantly, the May 2001 Genesis Acquisition, the Company acquired what
it considers to be substantial probable and possible oil and gas reserves in
Canada. The potential value of these reserves, on a risk-adjusted basis, was
considered in determining the value of developed oil and gas properties during
the Company's acquisition analyses. As a result of the possibility of
significant value attributable to the probable and possible reserves, the
Company changed its fair value definition for the purpose of impairment
determination as of January 1, 2001, to include the present value of
risk-adjusted probable and possible reserves. Had the Company calculated fair
value as of September 30, 2001, using the fair value as defined prior to 2001,
the impairment provision for the third quarter of 2001 related to its Canadian
producing oil and gas properties would have been approximately $43 million. The
change in the Company's fair value definition did not have any other material
effect on the Company's financial statements for the three-month and nine-month
periods ended September 30, 2001 and 2000.
In estimating the future net revenues, the Company assumed that the current
oil and gas price environment would continue and assumed operating costs would
escalate annually beginning at current levels. Due to the volatility of oil and
gas prices, it is possible that the Company's assumptions regarding oil and gas
prices may change in the future and may result in future impairment provisions.
Hedging
The Company periodically uses hedges (swap agreements) to reduce the impact
of oil and natural gas price fluctuations. Gains or losses on swap agreements
are recognized as adjustments to sales revenue when the related transactions
being hedged are finalized. Gains or losses from swap agreements that do not
qualify for accounting treatment as hedges are recognized currently as other
income or expense. The cash flows from such agreements are included in operating
activities in the consolidated statements of cash flows.
-9-
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("SFAS No. 133"). The FASB has subsequently
issued Statement No. 137 and Statement No. 138 which are amendments to SFAS No.
133. SFAS No. 133, as amended, establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133, as
amended, 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 income statement. 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 asset of approximately $18.5 million related to cash flow hedges in
place that are used to reduce the volatility in commodity prices for portions of
the Company's forecasted oil production. Additionally, the Company recorded, net
of tax, an adjustment to accumulated other comprehensive income in the
Stockholders' Equity section of the balance sheet of approximately $14.9
million. The amount recorded to accumulated other comprehensive income will be
relieved over time and taken to the income statement as the physical
transactions being hedged are finalized. A significant portion of the
Company's cash flow hedges in place at January 1, 2001, had settled as of
September 30, 2001, with the actual cash flow impact recorded in "Oil and gas
sales" on the Company's income statement. During the first nine months of 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 nine months ended September 30, 2001 and 2000, the Company made
cash payments for interest totaling approximately $31.2 million and $32.3
million, respectively. Cash payments made during the first nine months of 2001
and 2000 for U.S. Federal and state income taxes were approximately $12.9
million and $15.6 million, respectively. The Company made cash payments of
approximately $67.9 million and $7.2 million during the first nine months of
2001 and 2000, respectively, for foreign income taxes, primarily in Argentina.
Earnings Per Share
Basic earnings per common share for the third quarters of 2001 and 2000
were computed by dividing net income by the weighted average number of shares
outstanding during the period. Diluted earnings per common share for the third
quarters of 2001 and 2000 were computed assuming the exercise of all dilutive
options, as determined by applying the treasury stock method. In addition, for
the three month period ended September 30, 2001, the Company had outstanding
stock options for 2,620,000 additional shares of the Company's common stock,
with an average exercise price of $20.34, which were anti-dilutive. There were
729,000 anti-dilutive shares for the three month period ended September 30, 2000
at an average exercise price of $20.19.
-10-
Lease Operating Expense
For the three months ended September 30, 2001, the Company recorded in
lease operating expenses gross production taxes and transportation and storage
expenses of approximately $3.7 million and $3.3 million, respectively. For the
three months ended September 30, 2000, the Company recorded in lease operating
expenses gross production taxes and transportation and storage expenses of
approximately $4.4 million and $3.1 million, respectively.
For the nine months ended September 30, 2001, the Company recorded in lease
operating expenses gross production taxes and transportation and storage
expenses of approximately $13.4 million and $8.9 million, respectively. For the
nine months ended September 30, 2000, the Company recorded in lease operating
expenses gross production taxes and transportation and storage expenses of
approximately $11.9 million and $7.2 million, respectively.
Foreign Currency
The Company uses the U.S. dollar as its functional currency, except for the
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 functional currency are included in the
results of operations as incurred.
Cumulative Effect of Change in Accounting Principle
The Company adopted Securities and Exchange Commission Staff Accounting
Bulletin No. 101, Revenue Recognition ("SAB No. 101") in the fourth quarter of
2000, effective January 1, 2000. SAB No. 101 requires oil inventories held in
storage facilities to be valued at cost. Cost is defined as lifting costs plus
depreciation, depletion and amortization. The Company previously followed
industry practice by valuing oil inventories at market. The cumulative effect
reduced net income by $1.4 million, net of income tax effects of approximately
$0.6 million. Both the three month and nine month periods ended September 30,
2000, have been restated to give effect to this change in accounting principle.
Additional volatility in quarterly and annually reported earnings may occur in
the future as a result of fluctuations in oil inventory levels.
Transportation and Storage Costs
The Company adopted Emerging Issues Task Force Issue 00-10, Accounting for
Shipping and Handling Fees and Costs ("EITF 00-10") in the fourth quarter of
2000. EITF 00-10 requires that transportation and storage costs be shown as
expenses in the statement of operations and not deducted from revenues. The
Company previously followed industry practice by deducting transportation and
storage costs from revenues. The Company now records transportation and storage
costs as lease operating costs. Both the three month and nine month periods
ended September 30, 2000, have been restated to reflect the adoption of EITF
00-10. The adoption of EITF 00-10 did not impact net income.
-11-
Comprehensive Income
The Company had no non-owner changes in equity other than net income during
the nine months ended September 30, 2000. The Company had negative foreign
currency translation adjustments of approximately $20.3 million for the nine
months ended September 30, 2001, which it has included in accumulated other
comprehensive income in the Stockholders' Equity section of the accompanying
balance sheet. The Company also recorded under SFAS No. 133 a net reduction in
unrealized derivative gains, net of tax, of approximately $10.3 million related
to oil swaps, reducing the unrealized gains, net of tax, to $4.6 million at
September 30, 2001. This net reduction consisted of a $13.3 million reduction of
the transitional asset established on January 1, 2001 (initially $14.9 million),
for contracts in place at December 31, 2000, that settled during the first nine
months of 2001 and an increase for a current period change in value of $3.0
million for contracts to be settled in the fourth quarter of 2001 and the first
half of 2002. The actual cash flow impact of settled oil swaps ($12.9 million),
including those oil swaps entered into during 2001, has been reflected in the
"Oil and gas sales" line on the Company's statement of income for the nine
months ended September 30, 2001.
Other Balance Sheet Detail
The Company had $9.8 million and $3.3 million of value added tax
receivables related to its South American operations at September 30, 2001, and
December 31, 2000, respectively, included in other current assets. The Company
had $19.3 million and $5.0 million of accrued interest payable at September 30,
2001, and December 31, 2000, respectively, included in other payables and
accrued liabilities. The Company also had accrued property costs of $25.1
million and $14.6 million at September 30, 2001, and December 31, 2000,
respectively, included in other payables and accrued liabilities.
3. PUBLIC OFFERING
On May 30, 2001, the Company issued $200 million of its 7 7/8% Senior
Subordinated Notes due 2011 (the "7 7/8% Notes"). The 7 7/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after May 15, 2006. In addition, prior to May 15, 2004, the Company may redeem
up to 35 percent of the 7 7/8% Notes with the proceeds of certain underwritten
public offerings of the Company's common stock. The 7 7/8% Notes mature on May
15, 2011, with interest payable semiannually on May 15 and November 15 of each
year. All of the net proceeds to the Company from the sale of the 7 7/8% Notes
were used to repay a portion of the Company's existing indebtedness under its
revolving credit facility.
The 7 7/8% Notes are unsecured senior subordinated obligations of the
Company, rank subordinate in right of payment to all senior indebtedness (as
defined) and rank pari passu with the Company's 9% Senior Subordinated Notes Due
2005, its 8 5/8% Senior Subordinated Notes due 2009 and its 9 3/4% Senior
Subordinated Notes due 2009. The indenture for the 7 7/8% Notes contains
limitations on, among other things, additional indebtedness and liens, the
payment of dividends and other distributions, certain investments
and transfers or sales of assets.
-12-
4. RECENT PRONOUNCEMENTS
On July 20, 2001, the Financial Accounting Standards Board ("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 142, goodwill is no longer subject
to amortization over its estimated useful life. 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. SFAS No. 142
is required to be applied starting with fiscal years beginning after December
15, 2001.
The Company's May 2001 acquisition of Genesis Exploration Ltd. was
accounted for using the purchase method of accounting. Management plans to adopt
SFAS No. 142 effective January 1, 2002, resulting in the elimination of goodwill
amortization for future period statements of income. Management has not
determined at this time if the adoption of SFAS No. 142 will have any other
impact on the Company's financial position or results of operations.
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 entire
fair value of the retirement obligation as a liability at the time a well is
drilled or acquired. The liability will accrete over time with a charge to
interest expense. The new standard will apply to financial statements for the
years beginning after June 15, 2002. While the new standard will require that
the Company change its accounting for such abandonment obligations, the
Company has not had an opportunity to evaluate the impact of the new standard on
its financial statements.
In October 2001, the FASB issued Statement of Financial Accounting
Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets ("SFAS No. 144"). SFAS No. 144 establishes accounting and reporting
standards to establish a single accounting model, based on the framework
established in SFAS 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 provisions of SFAS No. 144 are effective for financial
statements issued for fiscal years beginning after December 15, 2001, and
interim periods within those fiscal years, with early application encouraged.
The provisions of SFAS No. 144 generally are to be applied prospectively. The
Company has not yet quantified the impact of adopting SFAS No. 144 on its
financial statements, but does not believe it will have a material impact on the
Company's financial position or results of operations.
-13-
5. 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,
sulfur 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 operating income before corporate general and
administrative costs and interest costs.
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, Trinidad and
Yemen. Summarized financial information for the Company's reportable segments
for the nine month and three month periods ended September 30, 2001 and 2000, is
shown in the tables on the following two pages:
-14-
(In thousands) Exploration and Production
------------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
--------- --------- --------- --------- --------- -------
Nine Months Ended 9/30/01
-------------------------
Revenues from external customers ............ $ 307,188 $ 60,130 $ 189,145 $ 12,724 $ 19,658 $ -
Intersegment revenues ....................... - - - - - -
Depreciation, depletion and
amortization expense ...................... 44,372 31,135 30,968 3,495 2,038 -
Impairment of oil and gas properties ........ 9,096 1,610 - - - -
Amortization of goodwill .................... - - - - - -
Operating income (loss) ..................... 159,600 3,309 114,284 6,224 10,813 (2,414)
Total assets ................................ 510,480 676,077 527,870 120,902 58,306 29,970
Capital investments ......................... 50,254 658,303 92,537 871 9,348 7,084
Long-lived assets ........................... 463,784 655,956 462,309 94,948 48,811 27,605
Nine Months Ended 9/30/00 (Restated)
------------------------------------
Revenues from external customers ............ $ 245,069 $ - $ 171,945 $ 12,084 $ 22,192 $ -
Intersegment revenues ....................... - - - - - -
Depreciation, depletion and
amortization expense ...................... 38,994 - 23,324 5,091 1,509 -
Operating income (loss) ..................... 130,250 - 111,172 (3,168) 15,344 (357)
Total assets ................................ 521,744 - 453,054 132,493 56,714 21,983
Capital investments ......................... 40,327 - 73,609 25,114 1,004 15,357
Long-lived assets ........................... 469,149 - 391,649 100,782 47,904 21,527
Gathering/ Gas
Plant Marketing Corporate Total
--------- --------- --------- ---------
Nine Months Ended 9/30/01
-------------------------
Revenues from external customers ............ $ 15,100 $ 115,295 $ 1,987 $ 721,227
Intersegment revenues (losses) .............. (580) 1,714 - 1,134
Depreciation, depletion and
amortization expense ...................... 1,942 - 2,110 116,060
Impairment of oil and gas properties ........ - - - 10,706
Amortization of goodwill .................... - - 7,191 7,191
Operating income (loss) ..................... (2,618) 3,131 (7,313) 285,016
Total assets ................................ 16,227 8,488 212,904 2,161,224
Capital investments ......................... 9,773 - 4,546 832,716
Long-lived assets ........................... 13,349 - 7,331 1,774,093
Nine Months Ended 9/30/00 (Restated)
------------------------------------
Revenues from external customers ............ $ 13,223 $ 82,868 $ 1,256 $ 548,637
Intersegment revenues ....................... 1,434 1,578 - 3,012
Depreciation, depletion and
amortization expense ...................... 1,143 - 1,572 71,633
Operating income (loss) ..................... 743 3,458 (314) 257,128
Total assets ................................ 11,000 23,156 39,859 1,260,003
Capital investments ......................... 79 - 1,748 157,238
Long-lived assets ........................... 6,065 - 4,950 1,042,026
-15-
(In thousands) Exploration and Production
------------------------------------------------------------------
Other
U.S. Canada Argentina Bolivia Ecuador Foreign
--------- --------- --------- --------- --------- -------
Three Months Ended 9/30/01
--------------------------
Revenues from external customers ............ $ 73,722 $ 27,955 $ 58,071 $ 4,383 $ 8,877 $ -
Intersegment revenues ....................... - - - - - -
Depreciation, depletion and
amortization expense ...................... 15,755 17,445 10,733 1,358 1,063 -
Impairment of oil and gas properties ........ 9,096 1,610 - - - -
Amortization of goodwill .................... - - - - - -
Operating income (loss) ..................... 17,095 (5,239) 32,495 1,895 4,769 (2,941)
Capital investments ......................... 18,221 26,702 62,458 118 3,073 5,932
Three Months Ended 9/30/00 (Restated)
------------------------------------
Revenues from external customers ............ $ 88,525 $ - $ 81,115 $ 6,914 $ 8,618 $ -
Intersegment revenues ....................... - - - - - -
Depreciation, depletion and
amortization expense ...................... 13,317 - 9,024 2,305 569 -
Operating income (loss) ..................... 48,852 - 57,748 (2,521) 5,071 (69)
Capital investments ......................... 15,736 - 52,133 12,691 113 6,559
Gathering/ Gas
Plant Marketing Corporate Total
--------- --------- --------- ---------
Three Months Ended 9/30/01
--------------------------
Revenues from external customers ............ $ 794 $ 20,481 $ (460) $193,823
Intersegment revenues (losses) .............. (158) 336 - 178
Depreciation, depletion and
amortization expense ...................... 888 - 830 48,072
Impairment of oil and gas properties ........ - - - 10,706
Amortization of goodwill .................... - - 4,417 4,417
Operating income (loss) ..................... (1,393) (60) (5,707) 40,914
Capital investments ......................... 171 - 1,218 117,893
Three Months Ended 9/30/00 (Restated)
------------------------------------
Revenues from external customers ............ $ 5,529 $ 38,988 $ 291 $229,980
Intersegment revenues ....................... 329 576 - 905
Depreciation, depletion and
amortization expense ...................... 391 - 591 26,197
Operating income (loss) ..................... 119 1,504 (297) 110,407
Capital investments ......................... 47 - 724 88,003
Intersegment sales are priced in accordance with the terms of existing
contracts and current market conditions. Capital investments include expensed
exploratory costs. Corporate general and administrative costs and interest costs
are not allocated to the operating income (loss) of the segments.
-16-
6. COMMITMENTS AND CONTINGENCIES
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 September 30, 2001, all
seismic obligations had been fulfilled and the first two exploratory wells had
been drilled and were being tested. The Company is obligated to drill the third
exploratory well under this commitment by February 2003 and currently estimates
its cost will be approximately $1.6 million.
The Company also is committed to drill four development wells on its Block
14 and Block 17 concessions in Ecuador (two wells each) during 2002. The Company
currently estimates its commitment for these wells to be approximately $15
million.
The Company had approximately $15.1 million in letters of credit
outstanding at September 30, 2001. These letters of credit relate primarily to
various obligations for acquisition and exploration activities in South America
and bonding requirements of various state regulatory agencies for U.S. 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.
7. SIGNIFICANT ACQUISITION
On May 2, 2001, the Company completed the acquisition of Canadian-based
Genesis Exploration Ltd. ("Genesis") for total consideration of $610 million,
including transaction costs and the assumption of the estimated net indebtedness
of Genesis at closing (the "Genesis Acquisition"). The cash portion of the
acquisition price was paid through advances under the Company's revolving credit
facility and cash on hand. The Genesis Acquisition was accounted for using
purchase accounting and, as such, only five months of Genesis activity are
included in the Company's statement of income for the nine month period ended
September 30, 2001.
The Company estimates that it acquired 62.2 million barrels of oil
equivalent ("BOE") of proved reserves in the transaction with Genesis,
consisting of approximately 27.7 million barrels of oil and 207.2 Bcf of gas.
Proved undeveloped reserves of oil and gas account for 33 percent of total
proved BOE of reserves. In addition, the Company estimates that the properties
have significant upside potential which may be realized through its 2001 work
program and beyond. The reserves acquired in the Genesis Acquisition are located
primarily in the provinces of Alberta and Saskatchewan, with a significant
exploration exposure in the Northwest Territories.
-17-
In addition to reserves, the Company acquired over one million net
undeveloped acres principally located in the areas of Alberta and Saskatchewan
with a significant portion, aggregating to 440,000 net acres, in the Northwest
Territories. Also, the Genesis Acquisition brings with it over 600 square-miles
of 3-D seismic and over 15,000 miles of 2-D seismic. The Company estimates the
acquisition cost of proved reserves was approximately $8.78 per BOE, exclusive
of $54 million allocated to undeveloped acreage and $9 million allocated to
facilities.
The Genesis Acquisition preliminary purchase price was allocated as of May
2, 2001, as follows (in thousands):
C$ US$ (a)
---------- ----------
Total purchase price ................................... $ 933,335 $ 609,624
Long-term debt assumed ................................. (135,000) (88,178)
Negative working capital assumed ....................... (89,766) (58,632)
---------- ----------
Amount paid ............................................ 708,569 462,814
Net assets at May 2, 2001 .............................. (196,912) (128,617)
---------- ----------
Excess of purchase price over net assets
at May 2, 2001 ....................................... $ 511,657 $ 334,197
========== ==========
Allocation of excess of purchase price over net assets:
Fair market value adjustment to oil and gas properties . $ 393,702 $ 257,153
SFAS No. 109 goodwill .................................. 273,640 178,733
Increase in deferred income taxes ...................... (150,630) (98,387)
Increase in accrued liabilities ........................ (5,055) (3,302)
---------- ----------
$ 511,657 $ 334,197
========== ==========
---------------
(a) Converted at the May 2, 2001, exchange rate of US$1/C$1.5310.
SFAS No. 109 goodwill will be amortized using a unit-of-production basis
over the total proved reserves acquired in accordance with Accounting Principles
Board Opinion No. 16, Business Combinations, until January 1, 2002, when the
Company formally adopts SFAS No. 142.
-18-
If the Genesis Acquisition had been consummated as of January 1, 2000, the
Company's unaudited pro forma revenues and net income for the nine months ended
September 30, 2001 and 2000, would have been as shown below; however, such pro
forma information is not necessarily indicative of what actually would have
occurred had the transaction occurred on such date.
Nine Months Ended
September 30,
-----------------
2001 2000
------ ------
(In thousands, except
per share amounts)
Revenues ............................................................................ $ 780,017 $ 629,192
Income before cumulative effect of change in accounting principle ................... 129,068 107,306
Net income .......................................................................... 129,068 105,884
Basic Income Per Share:
Income before cumulative effect of change in accounting principle ................. $ 2.05 $ 1.71
Net income ........................................................................ 2.05 1.69
Diluted Income Per Share:
Income before cumulative effect of change in accounting principle ................. $ 2.01 $ 1.68
Net income ........................................................................ 2.01 1.66
-19-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
The Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its exploitation and exploration activities.
Fluctuations in oil and gas prices have also significantly affected the
Company's results. The following table reflects the Company's oil and gas
production and its average oil and gas sales prices for the periods presented:
Three Months Ended September 30, Nine Months Ended September 30,
-------------------------------- -------------------------------
2001 2000 2001 2000
------------- ----------- ----------- -----------
Production:
Oil (MBbls) -
U.S. ............................ 2,108 2,259 6,438 6,731
Argentina ....................... 2,455(a) 2,572(b) 7,505(a) 6,623(b)
Ecuador ......................... 452(a) 325(b) 1,034(a) 909(b)
Bolivia ......................... 21(a) 44(b) 69(a) 87(b)
Canada .......................... 575 - 1,010 -
Total ......................... 5,611(a) 5,200(b) 16,056(a) 14,350(b)
Gas (MMcf) -
U.S. ............................ 8,533 8,787 26,137 26,931
Argentina ....................... 2,802 2,589 7,810 6,277
Bolivia ......................... 2,340 3,096 6,178 5,681
Canada .......................... 7,604 - 13,407 -
Total ......................... 21,279 14,472 53,532 38,889
Total MBOE ........................ 9,157 7,611 24,978 20,831
Average prices:
Oil (per Bbl) -
U.S. ............................ $ 23.22(c) $ 22.86(d) $ 24.56(c) $ 23.17(d)
Argentina ....................... 22.11(c) 29.71 23.76(c) 28.01
Ecuador ......................... 19.63 26.48 19.01 24.41
Bolivia ......................... 21.35 29.47 24.04 28.54
Canada .......................... 21.95 - 23.08 -
Total ......................... 22.31(c) 26.53(d) 23.73(c) 25.51(d)
Gas (per Mcf) -
U.S. ............................ $ 2.92 $ 4.24 $ 5.69 $ 3.31
Argentina ....................... 1.35 1.82 1.39 1.84
Bolivia ......................... 1.69 1.82 1.79 1.69
Canada .......................... 2.03 - 2.75 -
Total ......................... 2.26 3.29 3.88 2.83
-------------
(a) Total production for the three months and nine months ended September 30,
2001, before the impact of changes in inventories was 5,701 MBbls
(Argentina - 2,637 MBbls, Ecuador - 349 MBbls, Bolivia - 32 MBbls) and
16,316 MBbls (Argentina - 7,732 MBbls, Ecuador - 1,048 MBbls, Bolivia - 88
MBbls), respectively.
(b) Total production for the three months and nine months ended September 30,
2000, before the impact of changes in inventories was 5,037 MBbls
(Argentina - 2,409 MBbls, Ecuador - 331 MBbls, Bolivia - 38 MBbls) and
14,594 MBbls (Argentina - 6,901 MBbls, Ecuador - 880 MBbls, Bolivia - 82
MBbls), respectively.
(c) Reflects the impact of oil hedges which increased the three months and nine
months ended September 30, 2001, U.S., Argentina and total average oil
prices per Bbl by $0.62, $1.18 and $0.75, and $0.60, $1.20 and $0.81,
respectively.
(d) Reflects the impact of oil hedges which decreased the three months and nine
months ended September 30, 2000, U.S. and total average oil prices per Bbl
by $5.60 and $2.43, and $3.25 and $1.52, respectively.
-20-
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 seven percent decrease
in its average oil price, including the impact of hedging activities (15 percent
decrease excluding hedging activities), during the first nine months of 2001 as
compared to the same period of 2000. The Company's realized average oil price
for the first nine months of 2001 (before hedges) was approximately 82 percent
of the NYMEX reference price compared to 91 percent for the same period of 2000.
This decrease in realization was primarily the result of an increase in
differentials on the Company's Argentina and Ecuador production.
The Company participated in oil hedges covering 4.6 MMBbls and 6.5 MMBbls
during the first nine months of 2001 and 2000, respectively. The impact of the
2001 hedges increased the Company's U.S. average oil price for the first nine
months of 2001 by 60 cents to $24.56 per Bbl, its Argentina average oil price by
$1.20 to $23.76 per Bbl and its overall average oil price by 81 cents to $23.73
per Bbl. The impact of the 2000 hedges reduced the Company's U.S. average oil
price for the first nine months of 2000 by $3.25 to $22.86 per Bbl, and its
overall average oil price by $1.52 to $26.53 per Bbl.
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 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 is primarily determined by the realized price of oil from its El
Huemul concession; however, this contract expires at the end of 2001. The
Company anticipates securing long-term contracts for this gas during 2001;
however, it expects these future gas prices to be at lower levels than the
current contract. The Company's Canada gas is generally sold at spot market
prices as reflected by the AECO gas price index. The Company's total average gas
price for the first nine months of 2001 was 37 percent higher than the same
period of 2000.
-21-
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 hedges (swap agreements) for a total of 1.8 MMBbls of oil at a
weighted average price of $26.65 per Bbl (NYMEX reference price) for the last
quarter of 2001 and the first two quarters of 2002. The Company continues to
monitor oil and gas prices and may enter into additional oil and gas hedges or
swaps in the future. The following table reflects the barrels currently hedged
and the corresponding weighted average NYMEX reference prices by quarter:
NYMEX
Reference
Price
Quarter Ending Barrels Per Bbl
----------------- -------------- ----------
(in thousands)
December 31, 2001 920 $ 27.74
March 31, 2002 450 25.89
June 30, 2002 455 25.19
Relatively modest changes in either oil or gas prices significantly impact
the Company's results of operations and cash flow. However, the impact of
changes in the market prices for oil and gas on the Company's average realized
prices may be reduced from time to time based on the level of the Company's
hedging activities. Based on the first nine months of 2001 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 $10.0 million and $15.7 million,
respectively. A 10 cent per Mcf change in the average price realized, before
hedges, by the Company for gas would result in a change in net income and cash
flow before income taxes on an annual basis of approximately $3.3 million and
$5.3 million, respectively, based on gas production for the first nine months of
2001.
Period to Period Comparison
During December 2000 and May 2001, the Company made two acquisitions which
significantly impacted the period to period comparison for the third quarter and
the first nine months of 2001. These acquisitions (the "Canadian Acquisitions")
include the purchase of 100 percent of the outstanding common stock of Cometra
Energy (Canada) Ltd. (the "Cometra Acquisition") in December 2000 and the
purchase of 100 percent of the outstanding common stock of Genesis Exploration
Ltd. (the "Genesis Acquisition") in May 2001.
The Company's consolidated revenues and expenses for the third quarter and
first nine months of 2001 include, under the purchase method of accounting, the
consolidation of Cometra for a full three months and nine months, respectively,
and Genesis for the entire third quarter and the last five months of the nine
month period ended September 30, 2001.
-22-
Three months ended September 30, 2001, Compared to three months ended September
30, 2000
The Company reported net income of $6.2 million for the quarter ended
September 30, 2001, compared to net income of $58.5 million for the same period
in 2000. The primary reasons for the 89 percent decrease quarter over quarter
were a 31 percent decrease in average gas prices received by the Company and a
16 percent decrease in average oil prices, increases in lease operating
expenses, general and administrative costs, depreciation, depletion and
amortization, goodwill amortization and interest expense, all primarily as a
result of the Canadian Acquisitions, and a $1.6 million impairment charge
recorded during the third quarter of 2001 related to certain Canadian oil and
gas producing properties. The Company also recorded a $9.1 million impairment
charge during the third quarter of 2001 to reduce certain domestic producing oil
and gas properties being held for sale to the lower of cost or fair market
value. These properties, along with other properties, were sold at a public
auction during October and a gain of $6.7 million will be recorded in the fourth
quarter related to the sale, thus resulting in a net loss on disposition of $2.4
million.
Oil and gas sales decreased $12.3 million (7 percent), to $173.2 million
for the third quarter of 2001 from $185.5 million for the same period of 2000.
An eight percent increase in oil production was offset by a 16 percent decrease
in average oil prices, accounting for a decrease in oil revenues of $12.8
million. A 47 percent increase in gas production essentially offset a 31 percent
decrease in average gas prices, accounting for an increase in gas revenues of
$0.5 million. The Company's eight percent increase in oil production was
primarily a result of volumes associated with the Canadian Acquisitions. The
Company's gas production rose by 47 percent due primarily to the gas production
from the Canadian Acquisitions and increased gas production in the Company's
Argentina concessions.
Lease operating expenses, including production taxes, increased $16.4
million (39 percent), to $58.3 million for the third quarter of 2001 from $41.9
million for the same period of 2000. The increase in lease operating expenses is
due primarily to costs associated with properties acquired through the Canadian
Acquisitions. Lease operating expenses per equivalent barrel produced increased
16 percent to $6.37 in the third quarter of 2001 from $5.51 for the same period
in 2000, primarily the result of higher lease operating costs per equivalent
barrel related to the Company's recently acquired Canadian operations and to
non-recurring environmental cost reductions during the third quarter of 2000
related to the Company's U.S. operations. As the result of a Securities and
Exchange Commission mandate, transportation and storage costs billed to the
Company have been reclassified to lease operating expenses for all periods
shown. These costs had been previously reported as a reduction of oil and gas
revenues consistent with oil and gas industry practice. This reclassification
added 36 cents and 40 cents to the reported lease operating expense per BOE in
the third quarter of 2001 and 2000, respectively.
Exploration costs increased $0.7 million (8 percent), to $9.6 million for
the third quarter of 2001 from $8.9 million for the same period of 2000. During
the third quarter of 2001, the Company's exploration costs included $5.6 million
for unsuccessful exploratory drilling and leasehold impairments and $4.0 million
for seismic and other geological and geophysical costs. Exploration expenses for
the third quarter of 2000 consisted of $7.6 million for unsuccessful exploratory
drilling, $1.1 million for lease impairments and $0.2 million for other
geological and geophysical costs.
-23-
General and administrative expenses increased $3.7 million (39 percent), to
$13.1 million for the third quarter of 2001 from $9.4 million for the same
period of 2000, due primarily to costs associated with the Company's new
Canadian operations and personnel additions and consulting costs in conjunction
with the Company's higher level of capital expenditures. The Company's G&A per
BOE for the third quarter of 2001 was $1.43 compared to $1.24 for the same
period of 2000.
Depreciation, depletion and amortization increased $21.9 million (84
percent), to $48.1 million for the third quarter of 2001 from $26.2 million for
the same period of 2000, primarily due to a 20 percent increase in total
production and a higher DD&A rate associated with the properties acquired in the
Genesis Acquisition. The Company's average oil and gas DD&A rate per equivalent
barrel produced increased from $3.30 in the third quarter of 2000 to $5.05 in
the third quarter of 2001.
In connection with the Genesis Acquisition, the Company recorded at the
time of acquisition as an asset, goodwill in the amount of approximately $178.7
million. The Company is currently required under Accounting Principles Board
Opinion No. 17, Intangible Assets, to amortize this goodwill using the units-
of-production method over the total proved reserves of Genesis. The Company
recorded goodwill amortization expense of $4.4 million for the third quarter of
2001. In June 2001, Statement of Financial Accounting Standards No. 142,
Goodwill and Other Intangible Assets, was issued changing the rules regarding
goodwill. For fiscal years beginning January 1, 2002, companies are no longer
required to amortize goodwill, but rather must periodically review the fair
value of goodwill and record impairment charges to income when the fair value is
less than the book value of the goodwill.
As part of the Company's non-strategic producing oil and gas property
divestiture program, certain domestic properties have been selected to be sold
at public auctions during the fourth quarter of 2001. In accordance with
Statement of Financial Accounting Standards No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of
("SFAS No. 121"), the Company recorded a $9.1 million impairment charge in the
third quarter of 2001 to reduce certain of these properties to the lower of cost
or fair market value. These properties, along with other properties, were sold
at a public auction in October and a gain of $6.7 million will be recorded in
the fourth quarter related to the sale, thus resulting in a net loss on the
disposition of $2.4 million. The Company also recorded a $1.6 million impairment
charge during the third quarter of 2001 related to certain Canadian producing
oil and gas properties. No impairment charge was recorded in the third quarter
of 2000.
Interest expense increased $8.3 million (72 percent), to $19.9 million for
the third quarter of 2001 from $11.6 million for the same period of 2000, due
primarily to a 108 percent increase in the Company's total average outstanding
debt quarter over quarter, primarily as a result of the borrowings related to
and debt assumed with the Canadian Acquisitions. This increase was partially
offset by a decrease in the Company's average interest rate to 7.59 percent for
the third quarter of 2001 from 9.02 percent in the same period of 2000.
-24-
Nine months ended September 30, 2001, Compared to nine months ended September
30, 2000
The Company reported net income of $129.2 million for the nine months ended
September 30, 2001, compared to net income of $123.9 million for the
year-earlier period. The increase in the Company's net income is primarily due
to a 20 percent increase in production on an equivalent barrel basis, combined
with a 37 percent increase in average gas prices. The first nine months of 2000
also included a $16.3 million, net of tax, non-recurring charge against income
related to an unfavorable court decision in Argentina. After excluding this
charge from 2000 period to date earnings, the Company's net income for the first
nine months of 2001 was $11.0 million lower than the adjusted 2000 earnings for
the same period. This decrease is primarily the result of higher costs
associated with the Canadian Acquisitions offsetting the significant increase in
revenues due to higher gas prices and overall production.
Oil and gas sales increased $112.3 million (24 percent), to $588.6 million
for the first nine months of 2001 from $476.3 million for the nine months of
2000. A 37 percent increase in average gas prices coupled with a 38 percent
increase in gas production accounted for a $97.4 million increase in gas sales
for the first nine months of 2001 as compared to the year-earlier period. A 12
percent increase in oil production, partially offset by a seven percent decrease
in average oil prices, accounted for a $14.9 million increase in oil sales for
the first nine months of 2001 as compared to the year-earlier period. The 12
percent increase in oil production and the 38 percent increase in gas production
are primarily the result of the Canadian Acquisitions and the Company's
exploitation and exploration activities, partially offset by declines in U.S.
production.
As a result of an unfavorable decision by the Supreme Court of Argentina,
the Company had recorded as other expense in the first nine months of 2000 a
non-recurring charge of $ 25.1 million. No similar charge was incurred in the
first nine months of 2001.
Lease operating expenses, including production taxes, increased $42.3
million (36 percent), to $159.1 million for the first nine months of 2001 from
$116.8 million for the first nine months of 2000 primarily due to the 20 percent
increase in production, increased lease power and field services costs, an
increase in U.S. and Argentina severance taxes due to higher product prices and
certain one-time repair costs in the U.S. Lease operating expenses per
equivalent barrel produced increased 14 percent to $6.37 in the first nine
months of 2001 from $5.61 for the same period in 2000. As the result of a
Securities and Exchange Commission mandate, transportation and storage costs
billed to the Company have been reclassified to lease operating expenses for all
periods shown. These costs had been previously reported as a reduction of oil
and gas revenues consistent with oil and gas industry practice. This
reclassification added 36 cents and 34 cents to the reported lease operating
expense per BOE in the first nine months of 2001 and 2000, respectively.
Exploration costs increased $3.0 million (24 percent), to $15.3 million for
the first nine months of 2001 from $12.3 million for same period of 2000. During
the first nine months of 2001, the Company's exploration costs included $8.6
million for unsuccessful exploratory drilling and lease impairments and $6.7
million for seismic and other geological and geophysical costs. Exploration
costs for the first nine months of 2000 included $10.0 million for unsuccessful
exploratory drilling, primarily in Bolivia, $2.0 million for lease impairments
and $ 0.3 million for other geological and geophysical costs.
-25-
General and administrative expenses increased $8.5 million (30 percent), to
$37.2 million for the first nine months of 2001 from $28.7 million for the first
nine months of 2000 due primarily to costs associated with the Canadian
operations acquired through the Canadian Acquisitions and personnel additions
and consulting costs in conjunction with the Company's higher level of capital
expenditures. General and administrative expenses per equivalent barrel produced
increased to $1.49 for the first nine months of 2001 from $ 1.38 in the
year-earlier period.
Depreciation, depletion and amortization increased $44.5 million (62
percent), to $116.1 million for the first nine months of 2001 from $71.6 million
for the first nine months of 2000, due primarily to the 20 percent increase in
production on a BOE basis and the 35 percent increase in the average
amortization rate per equivalent barrel produced from $3.30 in the first nine
months of 2000 to $4.47 for the same period of 2001 primarily due to the Genesis
Acquisition.
Interest expense increased $9.8 million (27 percent), to $46.7 million for
the first nine months of 2001 from $36.9 million for the first nine months of
2000, due primarily to a 42 percent increase in the Company's total average
outstanding debt year over year. This increase was partially offset as the
Company's overall average interest rate decreased to 8.00 percent in the first
nine months of 2001 as compared to 8.81 percent in the year-earlier period
primarily as the result of lower rates on its floating- rate debt due to overall
market reductions and a significant increase in its lower-cost floating-rate
borrowings as a result of the Canadian Acquisitions.
Capital Expenditures
During the first nine months of 2001, the Company's total oil and gas
capital expenditures were $818.4 million, including $599.5 million for oil and
gas properties acquired in the Genesis Acquisition and $42.3 million for the
acquisition of the producing LaVentana concession in Argentina. In North
America, the Company's non-acquisition oil and gas capital expenditures totaled
$104.2 million. Exploitation activities accounted for $69.5 million of the North
America capital expenditures with exploration activities contributing $34.7
million. During the first nine months of 2001, the Company's international
non-acquisition oil and gas capital expenditures totaled $67.6 million,
including $50.3 million in Argentina on exploitation activities,
$9.3 million in Ecuador, principally on exploitation, and $7.0 million on
exploration projects in Trinidad and Yemen. The Company also spent another $1.0
million in other international areas.
As of September 30, 2001, the Company had total unevaluated oil and gas
property costs of approximately $107.2 million consisting of undeveloped
leasehold costs of $87.1 million, including $61.8 million in Canada, and
exploratory drilling in progress of $20.1 million. Approximately $20.3 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.
On May 2, 2001, the Company completed the Genesis Acquisition for total
consideration of $610 million, including transaction costs and the assumption of
the estimated net indebtedness of Genesis at closing (See Note 7 - Significant
Acquisition). The cash portion of the acquisition price was paid through
advances under the Company's revolving credit facility and cash on hand.
-26-
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 revised non- acquisition capital expenditure budget for 2001 and its
revised preliminary non-acquisition budget for 2002 are currently set at $238
million and $270 million, respectively. The Company does not have a specific
acquisition budget since the timing and size of acquisitions are difficult to
forecast. The Company continues to evaluate additional acquisitions of oil and
gas properties. In addition to internally-generated cash flow and advances under
its revolving credit facility, the Company may seek additional sources of
capital to fund any future significant acquisitions (see "Liquidity"), however,
no assurance can be given that sufficient funds will be available to fund the
Company's desired acquisitions.
Liquidity
Internally generated cash flow and the borrowing capacity under its
revolving credit facility are the Company's major sources of liquidity. In
addition, the Company may use other sources of capital, including the issuance
of additional debt securities or equity securities, to fund any major
acquisitions it might secure in the future and to maintain its financial
flexibility.
In the past, the Company has accessed the public markets to finance
significant acquisitions and provide liquidity for its future activities. Since
1990, in conjunction with the purchase of substantial oil and gas assets, the
Company completed five public equity offerings as well as two public debt
offerings and two Rule 144A debt offerings, which provided the Company with
aggregate net proceeds of approximately $843 million.
On May 30, 2001, the Company issued $200 million of its 7 7/8% Senior
Subordinated Notes due 2011 (the "7 7/8% Notes"). The 7 7/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after May 15, 2006. In addition, prior to May 15, 2004, the Company may redeem
up to 35 percent of the 7 7/8% Notes with the proceeds of certain underwritten
public offerings of the Company's common stock. The 7 7/8% Notes mature on May
15, 2011, with interest payable semiannually on May 15 and November 15 of each
year. All of the net proceeds to the Company from the sale of the 7 7/8% Notes
were used to repay a portion of the existing indebtedness under the Company's
revolving credit facility.
-27-
Under the Second Amended and Restated Credit Agreement dated November 30,
2000, as amended (the "Bank Facility"), certain banks have provided to the
Company a $625 million unsecured revolving credit facility. The Bank Facility
establishes a borrowing base determined by the banks' evaluation of the
Company's oil and gas reserves. The amount available to be borrowed under the
Bank Facility is limited to the lesser of the facility size or the borrowing
base, which is currently set at $850 million. While availability under the Bank
Facility is limited to the $625 million facility size, the $225 million of
borrowing base in excess of the $625 million Bank Facility provides additional
liquidity should the Company choose to incur additional indebtedness outside the
Bank Facility.
The Company's unused availability under the Bank Facility at November 2,
2001, was approximately $190 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.
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) 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 debt to the borrowing base. As of September 30, 2001, the Company had
$417.1 million outstanding under its Bank Facility, excluding outstanding
letters of credit of approximately $15.1 million. The Company must pay a
commitment fee ranging from 0.325 to 0.50 percent per annum on the unused
portion of the banks' commitment.
On a semiannual basis, the Company's borrowing base is redetermined by the
banks based upon their review of the Company's oil and gas reserves. If the sum
of outstanding senior debt exceeds the borrowing base, as redetermined, the
Company must repay such excess. Final maturity of the Bank Facility is November
30, 2005.
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. For the nine
months ended September 30, 2001, approximately 64 percent of the Company's
production was oil. Realized oil prices for the period decreased by seven
percent as compared to the same period of 2000 and total production on a BOE
basis increased by 20 percent. As a result, the Company's earnings and cash
flows materially increased compared to the first nine months of 2000. To the
extent oil and gas prices decline, the Company's earnings and cash flows from
operations may be adversely impacted. However, 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.
Inflation
In recent years, inflation has not had a significant impact on the
Company's operations or financial condition.
-28-
Income Taxes
The Company incurred a current provision for income taxes of approximately
$56.6 million and $49.1 million for the first nine months of 2001 and 2000,
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.
Change in Accounting Principles
The Company adopted Securities and Exchange Commission Staff Accounting
Bulletin No. 101, Revenue Recognition ("SAB No. 101"), in the fourth quarter of
2000, effective January 1, 2000. SAB No. 101 requires oil inventories held in
storage facilities to be valued at cost. Cost is defined as lifting costs plus
depreciation, depletion and amortization. The Company previously followed
industry practice by valuing oil inventories at market. The cumulative effect
reduced net income by $1.4 million, net of income tax effects of $0.6 million.
The first nine months of 2000 have been restated to give effect to this change
in accounting principle. Additional volatility in quarterly and annually
reported earnings may occur in the future as a result of the required adoption
of SAB No. 101 and fluctuations in oil inventory levels.
In June 1998, the Financial Accounting Standards Board 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 income statement. 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 asset 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
adjustment to accumulated other comprehensive income in the Stockholders' Equity
section of the balance sheet of $14.9 million. The amount recorded to
accumulated other comprehensive income will be relieved over time and taken to
the income statement as the physical transactions being hedged are finalized.
-29-
Foreign Operations
For information on the Company's foreign operations, see "Foreign Currency
and Operations Risk" under Item 3 of Part I of 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 and other such matters are
forward-looking statements. Although the Company believes the expectations
expressed in such forward-looking statements are based on reasonable assumptions
within the bounds of its knowledge of its business, such statements are not
guarantees of future performance and actual results or developments may differ
materially from those in the forward-looking statements.
Factors that could cause actual results to differ materially from those in
forward-looking statements include: oil and gas prices; exploitation and
exploration successes; continued availability of capital and financing; general
economic, market or business conditions; acquisition opportunities (or lack
thereof); changes in laws or regulations; risk factors listed from time to time
in the Company's reports filed with the Securities and Exchange Commission; and
other factors. The Company assumes no obligation to update publicly any
forward-looking statements, whether as a result of new information, future
events or otherwise.
-30-
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's operations are exposed to market risks primarily as a result
of changes in commodity prices, interest rates and foreign currency exchange
rates. The Company does not use derivative financial instruments for speculative
or trading purposes.
Commodity Price Risk
The Company produces, purchases and sells crude oil, natural gas,
condensate, natural gas liquids and sulfur. As a result, the Company's financial
results can be significantly impacted as these commodity prices fluctuate widely
in response to changing market forces. The Company has previously engaged in oil
and gas hedging activities and intends to continue to consider various hedging
arrangements to realize commodity prices which it considers favorable. During
2000 and the first nine months of 2001, the Company entered into various oil
hedges (swap agreements) for various periods of calendar 2001 for a total of
5.48 MMBbls of oil at a weighted average NYMEX reference price of $30.23 per
Bbl. The Company has also entered into various oil hedges (swap agreements) for
a total of 905 MBbls of oil at a weighted average NYMEX reference price of
$25.54 per Bbl for the first six months of 2002. The fair value of commodity
swap agreements is the amount at which they could be settled, based on quoted
market prices. At September 30, 2001, the Company would have received
approximately $4.1 million to terminate its oil swap agreements then in place
for the last quarter of 2001 covering a total 920 MMBbls of oil at an average
NYMEX reference price of $27.74 per Bbl and approximately $1.6 million to
terminate its oil swaps then in place for the first two quarters of 2002
covering a total of 905 MBbls of oil at an average NYMEX reference price of
$25.54 per Bbl. The Company currently has no gas price hedges in place. 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. However, the impact of
changes in the market prices for oil and gas on the Company's average realized
prices may be reduced from time to time based on the level of the
Company's hedging activities. Based on the first nine months of 2001 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 $10.0 million and $15.7
million, respectively. A 10 cent per Mcf change in the average price realized,
before hedges, by the Company for gas would result in a change in net income and
cash flow before income taxes on an annual basis of approximately $3.3 million
and $5.3 million, respectively, based on gas production for the first nine
months of 2001.
-31-
Interest Rate Risk
The Company's interest rate risk exposure results primarily from short-term
rates, mainly LIBOR- based, on borrowings from its commercial banks. To reduce
the impact of fluctuations in interest rates, the Company maintains a portion of
its total debt portfolio in fixed-rate debt. At September 30, 2001, the amount
of the Company's fixed-rate debt was 59 percent of its total long-term debt. In
the past, the Company has not entered into financial instruments such as
interest rate swaps or interest rate lock agreements. However, it may consider
these instruments to manage the impact of changes in interest rates based on
management's assessment of future interest rates, volatility of the yield curve
and the Company's ability to access the capital markets in a timely manner.
Based on the outstanding borrowings under variable rate debt instruments at
September 30, 2001, a change in the average interest rate of 100 basis points
would result in a change in net income and cash flow before income taxes on an
annual basis of approximately $2.5 million and $4.1 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: 2001 2002 2003 2004 2005 after Total 9/30/01
--------------- ---- ---- ---- ---- -------- -------- --------- -------
Fixed rate (in thousands)........... - - - - $149,827 $449,417 $599,244 $608,109
Average interest rate............... - - - - 9.0% 8.7% 8.8% -
Variable rate (in thousands)........ - - - - $417,100 - $417,100 $417,100
Average interest rate............... - - - - (a) - (a) -
(a) LIBOR plus an increment, based on level of outstanding senior debt to the
borrowing base, up to a maximum of 2.0 percent. The increment above LIBOR
at September 30, 2001, was 1.25 percent.
Foreign Currency and Operations Risk
International investments represent, and are expected to continue to
represent, a significant portion of the Company's total assets. The Company has
international operations in Argentina, Canada, Bolivia, Ecuador, Trinidad and
Yemen. For the first nine months of 2001, the Company's exploration and
production operations in Argentina accounted for approximately 26 percent of the
Company's revenues, 40 percent of the Company's operating income and 24 percent
of its total assets as of September 30, 2001. The Company's Canadian operations
accounted for approximately 31 percent of its total assets as of September 30,
2001. A majority of these Canadian assets were purchased on May 2, 2001, as part
of the Genesis Acquisition and the Company's exploration and production
operations include only five months of their activity during the first nine
months of 2001. During the first nine months of 2001, none of the Company's
other international operations accounted for more than 10 percent of its
revenues, operating income or total assets. The Company continues to identify
and evaluate international opportunities, but currently has no binding
agreements or commitments to make any material international investment. As a
result of such significant foreign operations, the Company's financial results
could be affected by factors such as changes in foreign currency exchange rates,
weak economic conditions or changes in the political climate in these foreign
countries.
-32-
Since 1999, Argentina's economy has been in recession. In an effort to
regain control of the economy, President Fernando de la Rua has appointed
Domingo Cavallo as Minister of Economy. Mr. Cavallo has been granted emergency
powers by Congress to introduce reforms to achieve an economic
reactivation by restoring growth and competitiveness. In May 2001, the
International Monetary Fund (the "IMF") approved a debt-swap and new fiscal
deficit targets in order to allow sufficient time for economic and fiscal
reforms to take effect. The Congress recently passed a "zero deficit" law, which
consists of emergency cuts in government spending with the goal of eliminating
the fiscal deficit. In effect, the government will spend only what it collects
in revenues.
After a recent loss of power in Congressional elections, the ruling Alianza
party has been unsuccessful at restructuring internal debt and creating new
economic measures with the provincial governors, and therefore Mr. Cavallo has
turned to external measures and is seeking from the IMF a full restructuring of
the country's public bond debt.
In the meantime, Mr. Cavallo continues to focus on improvement in tax
revenue, clamping down on tax evasion, lowering tariffs on imported capital
goods to lower the costs of investment and taxing financial transactions. The
Argentina congress has recently approved a proposal for the peso to shift from
fixed parity with the U.S. dollar to a link with a basket of currencies
including the euro and the U.S. dollar once the euro reaches a 1:1 exchange rate
with the U.S. dollar. Until then, the peso will still be tied to the U.S. dollar
only. Economic recovery will be led by new investment and by exports, but the
pace of growth will likely be constrained by the economic slow down in Brazil,
which is Argentina's main trading partner, and in the global economy.
All of the Company's Argentine revenues are U.S. dollar based, while a
large portion of its costs are denominated in Argentine pesos. The Company
believes that although there is a greater chance of devaluation of the peso if a
debt restructuring is not obtained, its revenues would be unaffected and its
operating costs would not be significantly increased. The Company's
indirectly-owned Argentina subsidiary, Vintage Petroleum Argentina S.A., had
value added tax receivables of approximately $21 million and tax net operating
loss carry forwards of approximately $87 million at September 30, 2001, which
are peso denominated for local reporting purposes. Should devaluation of the
peso occur, the Company may not recognize full value of these assets. The
carrying values of these assets, including a related deferred credit, at
September 30, 2001, was approximately $20 million. At the present time, there
are no foreign exchange controls preventing or restricting the conversion of
Argentine pesos into dollars.
Since the mid-1980's, Bolivia has been undergoing major economic reform,
including the establishment of a free-market economy and the encouragement of
foreign private investment. Economic activities that had been reserved for
government corporations were opened to foreign and domestic private investments.
Barriers to international trade have been reduced and tariffs lowered. A new
investment law and revised codes for mining and the petroleum industry, intended
to attract foreign investment, have been introduced.
-33-
The political environment in Bolivia will soon change as President Hugo
Banzer, after being stricken with cancer, has resigned and handed over power to
his Vice-President, Jorge Quiroga. Mr. Quiroga, who is a U.S. educated
industrial engineer, will run the country until new elections are held, which
are currently scheduled for next year. He will be barred from running in those
elections due to term limits.
In 1987, the Boliviano ("Bs") replaced the peso at the rate of one million
pesos to one Boliviano. The exchange rate is set daily by the Government's
exchange house, the Bolsin, which is under the supervision of the Bolivian
Central Bank. Foreign exchange transactions are not subject to any controls. The
US$:Bs exchange rate at September 30, 2001, was US$1:Bs 6.74. The Company
believes that any currency risk associated with its Bolivian operations would
not have a material impact on the Company's financial position or results of
operations.
In Ecuador, President Gustavo Naboa and Congress continue to debate further
tax, social, and customs reforms to strengthen economic growth. The legal basis
for many of the recent reforms is the Ley Fundamental para la Transformacion
Economica del Ecuador (the "economic transformation law") enacted in March 2000,
which mandated dollarization of the economy. As a result of this reform, all of
the Company's Ecuadorian revenues and costs are U.S. dollar based. Even though
the second phase of the economic transformation law (known as Trole II), which
was intended to bring significant tax and labor reform and a defined
privatization program to increase inflows of foreign direct investment, was
rejected by Congress, President Noboa used his veto powers to pass a tax reform
package which allowed the IMF to make a disbursement of its stand-by loan in the
second quarter. Having met the fiscal targets thus far in 2001 agreed to by the
IMF, the government will be seeking further stand-by financing for 2002. Fixed
investment has significantly increased in 2001 as construction of the new heavy
oil pipeline (the O.C.P.) continues to progress on schedule.
With the Cometra Acquisition in December 2000 and the Genesis Acquisition
in May 2001, the Company now has significant producing operations in Canada. The
Company views the operating environment in Canada as stable and the economic
stability as good. A majority of the Company's Canadian revenues and costs are
denominated in Canadian dollars. While the value of the Canadian dollar does
fluctuate in relation to the U.S. dollar, the Company believes that any currency
risk associated with its Canadian operations would not have a material impact on
the Company's financial position or results of operations. The US$:C$ exchange
rate at September 30, 2001, was US$1:C$1.5797 as compared to US$1:C$1.4995 at
December 31, 2000.
-34-
PART II
OTHER INFORMATION
-35-
Item 1. Legal Proceedings
-----------------
For information regarding legal proceedings, see the Company's
Form 10-K for the year ended December 31, 2000.
Item 2. Changes in Securities and Use of Proceeds
-----------------------------------------
not applicable
Item 3. Defaults Upon Senior Securities
-------------------------------
not applicable
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
not applicable
Item 5. Other Information
-----------------
Copies of the Company's press releases each dated November 7,
2001, announcing third quarter 2001 earnings results and revisions
to 2001 capital budget and growth targets and its revised
preliminary 2002 capital budget and growth targets are attached as
exhibits hereto and incorporated herein by reference.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
a) Exhibits
The following documents are included as exhibits to this
Form 10-Q. Those exhibits below incorporated by reference
herein are indicated as such by the information supplied in
the parenthetical thereafter. If no parenthetical appears
after an exhibit, such exhibit is filed herewith.
10. First Amendment to Second Amended and Restated Credit
Agreement dated as of August 8, 2001, between the
Company, the Lenders party thereto, Bank of Montreal,
as Administrative Agent, Bank of America, N.A., as
Syndication Agent, Societe General, Southwest Agency,
as Documentation Agent, and ABN AMRO Bank, N.V., as
Managing Agent (filed as Exhibit 10 to the Company's
report on Form 10-Q for the quarter ended June 30,
2001, filed on August 14, 2001).
99.1 Press release dated November 7, 2001, issued by the
Company announcing third quarter 2001 earnings
results.
-36-
99.2 Press release dated November 7, 2001, issued by the
Company announcing revisions to 2001 capital budget
and growth targets and its revised preliminary 2002
capital budget and growth targets.
b) Reports on Form 8-K
none
-37-
Signatures
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
VINTAGE PETROLEUM, INC.
-----------------------
(Registrant)
DATE: November 8, 2001 \s\ Michael F. Meimerstorf
------------------------------------
Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)
-38-
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
------ ------------------------------------------------------------
10. First Amendment to Second Amended and Restated Credit
Agreement dated as of August 8, 2001, between the Company,
the Lenders party thereto, Bank of Montreal, as
Administrative Agent, Bank of America, N.A., as Syndication
Agent, Societe General, Southwest Agency, as Documentation
Agent, and ABN AMRO Bank, N.V., as Managing Agent (filed as
Exhibit 10 to the Company's report on Form 10-Q for the
quarter ended June 30, 2001, filed on August 14, 2001).
99.1 Press release dated November 7, 2001, issued by the Company
announcing third quarter 2001 earnings results.
99.2 Press release dated November 7, 2001, issued by the Company
announcing revisions to 2001 capital budget and growth
targets and its revised preliminary 2002 capital budget and
growth targets.