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, 1998
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.)
4200 One Williams Center Tulsa, Oklahoma 74172
(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 10, 1998
Common Stock, $.005 Par Value 53,103,066
-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,
1998 1997
------------- ------------
(Restated)
CURRENT ASSETS:
Cash and cash equivalents $ 2,556 $ 5,797
Accounts receivable -
Oil and gas sales 51,367 60,878
Joint operations 5,686 6,358
Deferred income taxes - 4,206
Prepaids and other current assets 10,769 12,443
---------- ----------
Total current assets 70,378 89,682
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method 1,289,901 1,158,749
Oil and gas gathering systems 14,464 12,943
Other 11,034 8,420
---------- ----------
1,315,399 1,180,112
Less accumulated depreciation, depletion and amortization 450,672 373,225
---------- ----------
864,727 806,887
---------- ----------
OTHER ASSETS, net 29,669 18,825
---------- ----------
TOTAL ASSETS $ 964,774 $ 915,394
========== ==========
See notes to unaudited consolidated financial statements.
-3-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
LIABILITIES AND STOCKHOLDERS' EQUITY
September 30, December 31,
1998 1997
------------- ------------
(Restated)
CURRENT LIABILITIES:
Revenue payable $ 18,228 $ 27,085
Accounts payable - trade 18,916 21,088
Other payables and accrued liabilities 22,469 31,504
-------- --------
Total current liabilities 59,613 79,677
-------- --------
LONG-TERM DEBT 563,379 451,096
-------- --------
DEFERRED INCOME TAXES 25,652 43,135
-------- --------
OTHER LONG-TERM LIABILITIES 1,021 3,908
-------- --------
STOCKHOLDERS' EQUITY per accompanying statement:
Preferred stock, $.01 par, 5,000,000 shares authorized,
zero shares issued and outstanding - -
Common stock, $.005 par, 80,000,000 shares
authorized, 51,778,066 and 51,558,886 shares
issued and outstanding 259 258
Capital in excess of par value 203,916 202,008
Retained earnings 110,934 135,312
-------- --------
315,109 337,578
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $964,774 $915,394
======== ========
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,
--------------------- --------------------
1998 1997 1998 1997
-------- --------- --------- --------
(Restated) (Restated)
REVENUES:
Oil and gas sales $ 65,072 $ 88,901 $207,055 $258,264
Oil and gas gathering 1,476 4,300 6,811 13,514
Gas marketing 12,593 10,803 39,664 31,641
Other income 144 383 681 45
-------- -------- -------- --------
79,285 104,387 254,211 303,464
-------- -------- -------- --------
COSTS AND EXPENSES:
Lease operating, including production taxes 29,487 30,457 91,693 83,847
Exploration costs 6,569 2,408 18,939 8,321
Oil and gas gathering 1,334 3,590 5,851 11,354
Gas marketing 12,061 10,168 37,701 29,999
General and administrative 7,825 6,548 23,922 19,737
Depreciation, depletion and amortization 26,797 25,056 80,283 70,820
Interest 11,525 9,503 30,795 27,455
-------- -------- -------- --------
95,598 87,730 289,184 251,533
-------- -------- -------- --------
Income (loss) before income
taxes and minority interest (16,313) 16,657 (34,973) 51,931
PROVISION (BENEFIT) FOR INCOME TAXES:
Current (125) 1,308 (586) 3,293
Deferred (6,263) 1,823 (13,372) 6,147
MINORITY INTEREST IN
INCOME OF SUBSIDIARY - - - (203)
-------- -------- -------- --------
NET INCOME (LOSS) $ (9,925) $ 13,526 $(21,015) $ 42,288
======== ======== ======== ========
EARNINGS (LOSS) PER SHARE:
Basic $ $(.19) $ .26 $ (.41) $.83
======== ======== ======== ========
Diluted $ $(.19) $ .26 $ (.41) $.81
======== ======== ======== ========
Weighted average common shares outstanding:
Basic 51,733 51,549 51,664 51,049
======== ======== ======== ========
Diluted 51,733 53,180 51,664 52,403
======== ======== ======== ========
See notes to unaudited consolidated financial statements.
-5-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1998
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
Capital
Common Stock In Excess
----------------- of Par Retained
Shares Amount Value Earnings Total
------ ------ -------- -------- --------
Balance at December 31, 1997 (Restated) 51,559 $258 $202,008 $135,312 $337,578
Net loss - - - (21,015) (21,015)
Exercise of stock options and
resulting tax effects 219 1 1,908 - 1,909
Cash dividends declared
($.065 per share) - - - (3,363) (3,363)
------ ------ -------- -------- --------
Balance at September 30, 1998 51,778 $259 $203,916 $110,934 $315,109
====== ====== ======== ======== ========
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,
--------------------------
1998 1997
--------- ---------
(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (21,015) $ 42,288
Adjustments to reconcile net income (loss) to
cash provided by operating activities -
Depreciation, depletion and amortization 80,283 70,820
Exploration costs 18,939 8,321
Provision (benefit) for deferred income taxes (13,372) 6,147
Minority interest in income of subsidiary - 203
--------- ---------
64,835 127,779
Decrease in receivables 10,184 12,642
Decrease in payables and accrued liabilities (13,971) (2,294)
Other (4,062) (500)
--------- ---------
Cash provided by operating activities 56,986 137,627
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment -
Oil and gas properties (152,532) (202,124)
Other property and equipment (4,408) (1,886)
Purchase of subsidiary - (39,027)
Other (3,245) (987)
--------- ---------
Cash used by investing activities (160,185) (244,024)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock 879 47,910
Sale of 8 5/8% Senior Subordinated Notes - 96,270
Advances on revolving credit facility and other borrowings 123,651 174,858
Payments on revolving credit facility and other borrowings (16,515) (202,914)
Dividends paid (4,392) (2,266)
Other (3,665) (1,110)
--------- ---------
Cash provided by financing activities 99,958 112,748
--------- ---------
Net increase (decrease) in cash and cash equivalents (3,241) 6,351
Cash and cash equivalents, beginning of period 5,797 2,774
--------- ---------
Cash and cash equivalents, end of period $ 2,556 $ 9,125
========= =========
See notes to unaudited consolidated financial statements.
-7-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998 AND 1997
1. GENERAL
Effective January 1, 1998, the Company elected to change its accounting
method for oil and gas properties from the full cost method to the
successful efforts method. Management believes that the successful efforts
method is preferable and that the accounting change more accurately
presents the results of the Company's exploration and development
activities, minimizes asset write-offs caused by temporary declines in oil
and gas prices and reflects an impairment in the carrying value of the
Company's oil and gas properties only when there has been a permanent
decline in their fair value. As required by generally accepted accounting
principles, all financial statements presented herein have been
retroactively restated to give effect to this change in accounting method.
The accompanying financial statements are unaudited. The consolidated
financial statements include the accounts of the Company and its wholly-
and majority-owned subsidiaries. Management believes that all material
adjustments (consisting of only normal recurring adjustments) necessary for
a fair presentation have been made. These financial statements and notes
should be read in conjunction with the 1997 audited financial statements
and related notes, as restated in the Company's Form 8-K dated August 18,
1998.
On September 12, 1997, the Company's Board of Directors approved a two-for-
one stock split of its common stock effective October 7, 1997, to
stockholders of record on September 26, 1997. All references to the number
of shares and per share amounts in the financial statements and notes
thereto have been restated to reflect the stock split.
-8-
2. SIGNIFICANT ACCOUNTING POLICIES
Change in Accounting Method
As a result of the accounting change to the successful efforts method,
prior year and interim financial statements have been restated. The effect
of the restatements on the balance sheet as of September 30, 1997, is as
follows:
September 30, 1997
----------------------
Reported Restated
---------- ----------
(In thousands)
Assets:
Current Assets $ 79,214 $ 79,214
Property, Plant and Equipment, net 848,848 788,895
Other Assets 20,265 20,265
---------- ----------
Total Assets $ 948,327 $ 888,374
========== ==========
Liabilities and Stockholders' Equity:
Current Liabilities $ 69,154 $ 69,154
Long-Term Debt 447,868 447,868
Deferred Income Taxes 63,752 40,710
Other Long-Term Liabilities 2,531 2,531
Minority Interest 2,110 2,066
Stockholders' Equity 362,912 326,045
---------- ----------
Total Liabilities and Stockholders' Equity $ 948,327 $ 888,374
========== ==========
The effect of the accounting change on the income statements is as follows:
Three Months Ended Nine Months Ended
September 30,1997 September 30, 1997
-------------------- --------------------
Reported Restated Reported Restated
--------- --------- --------- ---------
(In thousands, except per share amounts)
Revenues $ 104,387 $ 104,387 $ 303,464 $ 303,464
Costs and Expenses 85,273 87,730 238,713 251,533
--------- --------- --------- ---------
Pretax Income 19,114 16,657 64,751 51,931
Income Taxes 3,880 3,131 14,092 9,440
Minority Interest - - (203) (203)
--------- --------- --------- ---------
Net Income $ 15,234 $ 13,526 $ 50,456 $ 42,288
========= ========= ========= =========
Earnings Per Share:
Basic $ .30 $ .26 $ .99 $ .83
Diluted $ .29 $ .26 $ .96 $ .81
-9-
Oil and Gas Properties
Under the successful efforts method of accounting, the Company capitalizes
all costs related to property acquisitions and successful exploratory
wells, all development costs and the costs of support equipment and
facilities. All costs related to unsuccessful exploratory wells are
expensed when such wells are determined to be non-productive; other
exploration costs, including geological and geophysical costs, are expensed
as incurred. The Company recognizes gain or loss on the sale of properties
on a field basis.
Unproved leasehold costs are capitalized and are reviewed periodically for
impairment. Costs related to impaired prospects are charged to expense.
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 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.
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 the carrying value over fair value. Fair value is defined as the
present value of the estimated future net revenues from the production of
oil and gas over the economic life of the reserves. No impairment provision
was required during the nine month periods ended September 30, 1998 and
1997.
Prior to the adoption of 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"), on January 1, 1996, the Company
determined the impairment of oil and gas properties on a world-wide basis.
The Company would record an impairment provision based on the excess of
capitalized costs over the undiscounted net revenues from proved reserves
using period-end prices. The impact of implementing SFAS No.121 was not
significant.
Statements of Cash Flows
Cash payments for interest totaled $28,985,776 and $22,384,069 and cash
payments for U.S. Federal and state income taxes were $1,473,252 and
$3,385,382 during the nine months ended September 30, 1998 and 1997,
respectively. During the nine months ended September 30, 1998 and 1997, the
Company made cash payments of $1,256,041 and $5,204, respectively, for
foreign income taxes.
-10-
Income Taxes
Deferred income taxes are provided on transactions which are recognized in
different periods for financial and tax reporting purposes. Such temporary
differences arise primarily from the deduction of certain oil and gas
exploration and development costs which are capitalized for financial
reporting purposes and differences in the methods of depreciation. The
Company follows the provisions of Statement of Financial Accounting
Standards No. 109 when calculating the deferred income tax provision for
financial purposes.
Earnings Per Share
In February 1997, the Financial Accounting Standards Board issued Statement
No. 128, Earnings Per Share ("SFAS No. 128"), establishing new standards
for computing and presenting earnings per share. The provisions of SFAS No.
128 are effective for earnings per share calculations for periods ending
after December 15, 1997. The Company has adopted SFAS No. 128 effective
December 31, 1997, and all earnings per share amounts disclosed herein have
been calculated under the provisions of SFAS No. 128. The adoption of SFAS
No. 128 did not have a material effect on previously reported earnings per
share or on 1997 earnings per share. Basic earnings per common share were
computed by dividing net income by the weighted average number of shares
outstanding during the period. Diluted earnings per common share were
computed assuming the exercise of all dilutive options, as determined by
applying the treasury stock method. Because the Company reported a loss for
the three months and nine months ended September 30, 1998, all options were
considered to be anti-dilutive and therefore were not included in the
calculation of diluted earnings per share for those periods.
Comprehensive Income
In June 1997, the Financial Accounting Standards Board issued Statement No.
130, Reporting Comprehensive Income ("SFAS No. 130"), establishing
standards for reporting and display of comprehensive income and its
components in financial statements. SFAS No. 130 defines comprehensive
income as the total of net income and all other non-owner changes in
equity. The Company had no non-owner changes in equity other than net
income and losses during the three month and nine month periods ended
September 30, 1998 and 1997.
Derivatives and Hedging Activities
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities ("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.
-11-
SFAS No. 133 is effective for fiscal years beginning after June 15, 1999,
however, companies may implement the statement as of the beginning of any
fiscal quarter beginning June 16, 1998. SFAS No. 133 cannot be applied
retroactively and must be applied to (a) derivative instruments and (b)
certain derivative instruments embedded in hybrid contracts that were
issued, acquired, or substantively modified after December 31, 1997 (and,
at the company's election, before January 1, 1998).
The Company has not yet quantified the impact of adopting SFAS No. 133 on
its financial statements and has not determined the timing of or method of
the adoption of SFAS No. 133. In September 1998, the Company entered into
ten natural gas basis swaps for the calender year 1999 covering a total of
82,000 MMBtu of gas per day. Natural gas basis swaps are used to hedge the
basis differential between the derivative financial instrument index price
and industry delivery point indexes. While the Company has not yet
quantified the impact of SFAS No. 133 on these derivative instruments, it
does not believe it would have a material adverse impact on the Company's
financial condition or results of operations.
3. LONG-TERM DEBT
Long-term debt at September 30, 1998, and December 31, 1997, consisted of
the following:
September 30, December 31,
1998 1997
------------- ------------
(In thousands)
Revolving credit facility $ 314,400 $ 202,200
Senior subordinated notes -
9% Notes due 2005, less unamortized
discount 149,704 149,674
8 5/8% Notes due 2009, less unamortized
discount 99,275 99,222
------------- ------------
$ 563,379 $ 451,096
============= ============
Revolving Credit Facility
The Company has available an unsecured revolving credit facility under an
Amended and Restated Credit Agreement dated October 21, 1998 (the "Credit
Agreement"), between the Company and certain banks. The Credit Agreement
establishes a borrowing base (currently $550 million including the impact
of the Western Acquisition and the Texaco Acquisition discussed in Note 4
below) based on the banks' evaluation of the Company's oil and gas
reserves.
Outstanding advances under the Credit Agreement 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. In addition,
the Company must pay a commitment fee ranging from 0.25 to 0.375 percent
per annum on the unused portion of the banks' commitment.
-12-
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. Any principal advances outstanding at
September 11, 2001, will be payable in 8 equal consecutive quarterly
installments commencing December 1, 2001, with final maturity at September
11, 2003.
The terms of the Credit Agreement impose certain restrictions on the
Company regarding the pledging of assets and limitations on additional
indebtedness. In addition, the Credit Agreement requires the maintenance of
a minimum current ratio (as defined) and tangible net worth (as defined) of
$250 million plus 75 percent of the net proceeds of any future equity
offerings.
SENIOR SUBORDINATED NOTES
On December 20, 1995, the Company issued $150 million of its 9% Senior
Subordinated Notes Due 2005 (the "9% Notes"). The 9% Notes are redeemable
at the option of the Company, in whole or in part, at any time on or after
December 15, 2000. The 9% Notes mature on December 15, 2005, with interest
payable semiannually on June 15 and December 15 of each year.
On February 5, 1997, the Company issued $100 million of its 8 5/8% Senior
Subordinated Notes Due 2009 (the "8 5/8% Notes"). The 8 5/8% Notes are
redeemable at the option of the Company, in whole or in part, at any time
on or after February 1, 2002. The 8 5/8% Notes mature on February 1, 2009,
with interest payable semiannually on February 1 and August 1 of each year.
The 9% Notes and 8 5/8% Notes (collectively, the "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
each other. Upon a change in control (as defined) of the Company, holders
of the Notes may require the Company to repurchase all or a portion of the
Notes at a purchase price equal to 101 percent of the principal amount
thereof, plus accrued and unpaid interest. The indentures for the Notes
contain limitations on, among other things, additional indebtedness and
liens, the payment of dividends and other distributions, certain
investments and transfers or sales of assets.
4. SUBSEQUENT EVENTS
Subsequent to September 30, 1998, the Company announced that it had made
three separate acquisitions of producing oil and gas properties. Two were
in the form of asset acquisitions and the third was a stock acquisition.
All three acquisitions will be accounted for using the purchase method.
On October 29, 1998, producing oil and gas properties located in East Texas
were purchased from Western Gas Resources, Inc. for $47.4 million in cash
(the "Western Acquisition"). On November 10, 1998, producing oil and gas
properties located in northern California were purchased from Texaco
Exploration and Production, Inc. and an affiliate for $28.7 million in cash
(the "Texaco Acquisition"). Funds for both acquisitions were provided
through advances on the Company's revolving credit facility and both
acquisitions included provisions for post-closing adjustments to the
purchase prices.
On November 4, 1998, the Company, through a wholly-owned subsidiary,
purchased from Elf Aquitaine 100 percent of the outstanding shares of its
French subsidiary, Elf Hydrocarbures Equateur, S.A. ("EHE"). EHE has
producing oil and gas operations, along with substantial undeveloped
acreage, in Ecuador. The acquisition price for EHE was $39.7 million,
including working capital of $7.2 million, and was funded through a cash
payment of $13.2 million provided through an advance on the Company's
revolving credit facility and the issuance of 1,325,000 shares of common
stock of the Company valued at a guaranteed amount of $20 per share, or
$26.5 million. If the prevailing share price is not equal to at least $20
per share after two years, then the Company will be required to deliver
additional consideration under the price guarantee provisions of the
agreement. Such additional consideration, if any, is payable, at the
Company's option, in cash or additional shares of the Company's common
stock. The legal transfer of the stock of EHE to the Company is subject to
the prior approval by the Ecuadorian government.
-13-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
CHANGE IN ACCOUNTING METHOD
Effective January 1, 1998, the Company elected to convert from the full
cost method to the successful efforts method of accounting for its investments
in oil and gas properties. The Company believes that the successful efforts
method of accounting is preferable, as it more accurately presents the results
of the Company's exploration and development activities, minimizes asset write-
offs caused by temporary downward oil and gas price movements and reflects an
impairment in the carrying value of its oil and gas properties only when there
has been a permanent decline in their fair value. Accordingly, the December 31,
1997, consolidated balance sheet, the consolidated statements of income for the
three months and nine months ended September 30, 1997, and the consolidated
statement of cash flows for the nine months ended September 30, 1997, included
in this Form 10-Q have been restated to conform with successful efforts
accounting. (See the Company's Form 8-K dated August 18, 1998, for the restated
financial statements and notes thereto for the years ended December 31, 1997,
1996 and 1995, and selected financial data for the three months ended
March 31, 1998.) The effect, net of income taxes, was to reduce December
31, 1997, retained earnings by $46.0 million. For the statements of income for
the three months and nine months ended September 30, 1997, the effect of the
accounting change was to decrease net income by $1.7 million ($.03 per diluted
share) and $8.2 million ($.15 per diluted share), respectively.
-14-
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 prices for the periods presented:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1998 1997 1998 1997
------- ------- ------- -------
Production:
Oil (MBbls) -
U.S. (1)........... 2,500 2,560 7,509 7,090
Argentina.......... 1,552 1,430 4,637 4,157
Bolivia............ 30 39 99 98
Total.............. 4,082 4,029 12,245 11,345
Gas (MMcf) -
U.S. (1)........... 10,386 10,020 31,530 26,202
Bolivia............ 1,372 1,711 4,036 4,554
Total.............. 11,758 11,731 35,566 30,756
Total MBOE (1)......... 6,042 5,984 18,172 16,471
Average prices:
Oil (per Bbl) -
U.S................ $ 11.08 $ 16.10 $ 11.64 $ 17.47
Argentina.......... 10.43 16.29 11.18 17.11
Bolivia............ 10.24 13.81 11.49 16.18
Total.............. 10.83 16.15 11.46 17.33
Gas (per Mcf) -
U.S................ $ 1.91 $ 2.21 $ 2.01 $ 2.16
Bolivia............ .73 1.02 .81 1.12
Total.............. 1.77 2.03 1.87 2.01
- --------------------
(1) First nine months of 1998 production was reduced by approximately 167 MBbls
of oil and 877 MMcf of gas, or 313 MBOE, due to severe weather conditions
in California and the Gulf of Mexico. Third quarter 1998 production was
reduced by approximately 8 MBbls of oil and 391 MMcf of gas, or 73 MBOE,
due to severe weather conditions in California and the Gulf of Mexico.
-15-
Average U.S. oil prices received by the Company fluctuate generally with
changes in the West Texas Intermediate ("WTI") posted prices for oil. The
Company's Argentina oil production is sold at WTI spot prices less a specified
differential. The Company experienced a 34 percent decrease in its average oil
price in the first nine months of 1998 compared to the first nine months of
1997. During the first nine months of 1997, the impact of Argentina oil hedges
reduced the Company's overall average oil price 23 cents to $17.33 per Bbl and
its average Argentina oil price was reduced 64 cents to $17.11 per Bbl. The
Company was not a party to any oil hedges in the first nine months of 1998. The
Company realized an average oil price for the first nine months of 1998 which
was approximately 92 percent of WTI posted prices compared to a realization of
93 percent (before the impact of oil hedges) of WTI posted prices for the year
earlier nine months. However, due to an increase in the differential between
WTI posted prices and the NYMEX reference price ("NYMEX"), the Company's average
realized prices (before hedges) declined to 77 percent of NYMEX in the first
nine months of 1998 compared to 84 percent of NYMEX in the first nine months of
1997.
Average U.S. gas prices received by the Company fluctuate generally with
changes in spot market prices, which may vary significantly by region. 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. During
1998, these fuel oil indexes have decreased in conjunction with the current low
oil price environment. The Company's average gas price for the first nine
months of 1998 was seven percent lower than 1997's first nine months.
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. Currently, there are no oil or
gas hedges in place related to 1998 production. In September 1998, the Company
entered into ten natural gas basis swaps for the calender year 1999 covering a
total of 82,000 MMBtu of gas per day. These natural gas basis swaps were used to
hedge the basis differential between the NYMEX reference price and industry
delivery point indexes under which the gas is sold.
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 third quarter 1998 oil production, a change in the
average oil price realized by the Company of $1.00 per Bbl would result in a
change in net income and cash flow before income taxes on a quarterly basis of
approximately $2.5 million and $4.0 million, respectively. A 10 cent per Mcf
change in the average price realized by the Company for gas would result in a
change in net income and cash flow before income taxes on a quarterly basis of
approximately $0.7 million and $1.1 million, respectively, based on third
quarter 1998 gas production.
PERIOD TO PERIOD COMPARISON
THREE MONTHS ENDED SEPTEMBER 30, 1998, COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 1997
The Company reported a net loss of $9.9 million for the quarter ended
September 30, 1998, compared to net income of $13.5 million for the same period
in 1997. An increase in the Company's oil and gas production of one percent on
an equivalent barrel basis was more than offset by a 33 percent decrease in
average oil prices and a 13 percent decrease in average gas prices.
-16-
Oil and gas sales decreased $23.8 million (27 percent), to $65.1 million
for the third quarter of 1998 from $88.9 for the third quarter of 1997. A 33
percent decrease in average oil prices, partially offset by a one percent
increase in oil production, accounted for a decrease of $20.8 million. A 13
percent decrease in average gas prices accounted for an additional decrease of
$3.0 million.
Oil and gas gathering net margins decreased $0.6 million (80 percent), to
$0.1 million for the third quarter of 1998 from $0.7 million for the third
quarter of 1997, due primarily to the sale by the Company of its two largest
gathering systems in December 1997 and June 1998.
Lease operating expenses, including production taxes, decreased $1.0
million (3 percent), to $29.5 million for the third quarter of 1998 from $30.5
million for the third quarter of 1997. The decrease in lease operating expenses
is due primarily to the Company's continued efforts to reduce operating costs.
Third quarter 1998 costs included estimated costs of $225,000 related to storm
damage repair and cleanup as a result of the severe weather in the Gulf of
Mexico. Lease operating expenses per equivalent barrel produced decreased to
$4.88 ($4.84 before the effects of the severe weather in the Gulf of Mexico) in
the third quarter of 1998 from $5.09 for the same period in 1997.
Exploration costs increased $4.2 million (173 percent), to $6.6 million for
the third quarter of 1998 from $2.4 million for the third quarter of 1997.
During the third quarter of 1998, the Company's exploration costs included $2.8
million for the acquisition of 3-D seismic data primarily in the U.S. Gulf Coast
area and Bolivia, $2.2 million for unsuccessful exploratory drilling, $1.2
million for lease expirations and $0.4 million in other geological and
geophysical costs. The Company's third quarter 1997 exploration costs consisted
primarily of $1.5 million in 3-D seismic acquisition costs in the U.S. and South
America and $0.9 million related to unsuccessful exploratory drilling.
General and administrative expenses increased $1.3 million (20 percent), to
$7.8 million for the third quarter of 1998 from $6.5 million for the third
quarter of 1997. General and administrative expenses increased primarily due to
the Company's increased emphasis on exploration activities, and additional costs
associated with international acquisition and business development activities.
Depreciation, depletion and amortization increased $1.7 million (7
percent), to $26.8 million for the third quarter of 1998 from $25.1 million for
the third quarter of 1997. The Company's average DD&A rate per equivalent barrel
produced for the third quarter of 1998 was $4.23 compared to $4.07 in the year
earlier period.
Interest expense increased $2.0 million (21 percent), to $11.5 million for
the third quarter of 1998 from $9.5 million for the third quarter of 1997, due
primarily to a 21 percent increase in the Company's total average outstanding
debt and costs of $0.5 million related to the restructuring of the Company's
unsecured revolving credit facility. The increase in interest expense was
partially offset by a decrease in the Company's overall average interest rate
from 7.99% in the third quarter of 1997 to 7.74% in the third quarter of 1998.
-17-
NINE MONTHS ENDED SEPTEMBER 30, 1998, COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 1997
The Company reported a net loss of $21.0 million for the nine months ended
September 30, 1998, compared to net income of $42.3 million for the same period
in 1997. An increase in the Company's oil and gas production of 10 percent on
an equivalent barrel basis was more than offset by a 34 percent decrease in
average oil prices and a seven percent decrease in average gas prices. The
production increases primarily relate to the acquisition of certain oil and gas
properties from Burlington Resources Inc. (the "Burlington Properties") in April
1997, the exploitation activities in Argentina and the exploration activities in
the Galveston Bay area in the Gulf of Mexico. The production increases were
reduced by the impact of the severe weather in California during the first
quarter of 1998 and the Gulf of Mexico in the third quarter of 1998. The
resulting mudslides and flooding in California and the presence of various
hurricanes in the Gulf of Mexico forced the Company to temporarily shut-in some
of its oil and gas properties for portions of the first three quarters lowering
production for the first nine months of 1998 by approximately 167,000 barrels of
oil and 877,000 Mcf of gas.
Oil and gas sales decreased $51.2 million (20 percent), to $207.1 million
for the first nine months of 1998 from $258.3 million for the first nine months
of 1997. A 34 percent decrease in average oil prices, partially offset by an
eight percent increase in oil production, accounted for a decrease of $56.2
million. A 16 percent increase in gas production, partially offset by a seven
percent decrease in average gas prices, reduced by $5.0 million the negative
impact of the decline in average oil prices.
Oil and gas gathering net margins decreased $1.2 million (56 percent), to
$1.0 million for the first nine months of 1998 from $2.2 million for the first
nine months of 1997, due primarily to the sale by the Company of its two largest
gathering systems in December 1997 and June 1998.
Lease operating expenses, including production taxes, increased $7.9
million (9 percent), to $91.7 million for the first nine months of 1998 from
$83.8 million for the first nine months of 1997. The increase in lease operating
expenses is in line with the 10 percent increase in production and is due
primarily to operating costs associated with the Burlington Properties and
estimated costs of $2.2 million for the first nine months of 1998 related to
storm damage repair and cleanup as a result of the severe weather in California
and the Gulf of Mexico. Lease operating expenses per equivalent barrel produced
decreased to $5.05 ($4.95 before the effects of the severe weather in California
and the Gulf of Mexico) in the first nine months of 1998 from $5.09 for the same
period in 1997.
Exploration costs increased $10.6 million (128 percent), to $18.9 million
for the first nine months of 1998 from $8.3 million for the comparable period in
1997. During the first nine months of 1998, the Company's exploration costs
included $12.8 million for the acquisition of 3-D seismic data primarily in the
U.S. Gulf Coast area and Bolivia, $2.7 million for unsuccessful exploratory
drilling, $1.9 million for lease expirations and $1.5 million in other
geological and geophysical costs. The Company's first nine months 1997
exploration costs consisted primarily of $5.3 million in 3-D seismic acquisition
costs, $1.5 million related to the abandonment of a non-commercial discovery in
Ecuador, and $1.5 million in other unsuccessful exploratory drilling costs.
-18-
General and administrative expenses increased $4.2 million (21 percent), to
$23.9 million for the first nine months of 1998 from $19.7 million for the first
nine months of 1997, due primarily to the addition of personnel as a result of
the acquisition of the Burlington Properties and the Company's increased
emphasis on exploration activities, and additional costs associated with
international acquisition and business development activities and unsuccessful
acquisition activities.
Depreciation, depletion and amortization increased $9.5 million (13
percent), to $80.3 million for the first nine months of 1998 from $70.8 million
for the first nine months of 1997, due primarily to the 10 percent increase in
production on an equivalent barrel basis. The Company's average DD&A rate per
equivalent barrel produced for the first nine months of 1998 was $4.25 compared
to $4.18 for the year earlier period.
Interest expense increased $3.3 million (12 percent), to $30.8 million for
the first nine months of 1998 from $27.5 million for the first nine months of
1997, due primarily to a 17 percent increase in the Company's total average
outstanding debt as a result of the acquisition of the Burlington Properties in
April 1997 and increased capital spending in the Company's exploitation and
exploration programs. The increase in interest expense was partially offset by
a decrease in the Company's overall average interest rate from 8.04% in the
first nine months of 1997 to 7.80% in the first nine months of 1998.
CAPITAL EXPENDITURES
During the first nine months of 1998, the Company's domestic oil and gas
capital expenditures totaled $94.1 million. Exploratory activities accounted
for $50.1 million of the domestic capital expenditures with exploitation
activities contributing $44.0 million. During the first nine months of 1998,
the Company's international oil and gas capital expenditures totaled $60.0
million, including $38.2 million in Argentina, primarily on exploitation
activities, and $16.9 million in Bolivia, primarily on exploration activities.
Subsequent to September 30, 1998, the Company announced that it had made
three separate acquisitions of producing oil and gas properties. Two were in
the form of asset acquisitions and the third was a stock acquisition. All three
acquisitions will be accounted for using the purchase method.
On October 29, 1998, producing oil and gas properties located in East Texas
were purchased from Western Gas Resources, Inc. for $47.4 million in cash (the
"Western Acquisition"). On November 10, 1998, producing oil and gas properties
located in northern California were purchased from Texaco Exploration and
Production, Inc. and an affiliate for $28.7 million in cash (the "Texaco
Acquisition"). Funds for both acquisitions were provided through advances on the
Company's revolving credit facility and both acquisitions included provisions
for post-closing adjustments to the purchase prices.
-19-
On November 4, 1998, the Company, through a wholly-owned subsidiary,
purchased from Elf Aquitaine 100 percent of the outstanding shares of its French
subsidiary, Elf Hydrocarbures Equateur, S.A. ("EHE"). EHE has producing oil and
gas operations, along with substantial undeveloped acreage, in Ecuador. The
acquisition price for EHE was $39.7 million, including working capital of $7.2
million, and was funded through a cash payment of $13.2 million provided through
an advance on the Company's revolving credit facility and the issuance of
1,325,000 shares of common stock of the Company valued at a guaranteed amount of
$20 per share, or $26.5 million. If the prevailing share price is not equal to
at least $20 per share after two years, then the Company will be required to
deliver additional consideration under the price guarantee provisions of the
agreement. Such additional consideration, if any, is payable, at the Company's
option, in cash or additional shares of the Company's common stock. The legal
transfer of the stock of EHE to the Company is subject to the prior approval by
the Ecuadorian government.
The Company is committed to perform 17,728 work units related to its
concession rights in the Naranjillos field in Santa Cruz Province, Bolivia
awarded in late 1997. The work unit commitment is guaranteed by the Company
through an $88.6 million letter of credit; however, the Company anticipates that
it will fulfill this three-year work unit commitment through approximately $50
to $60 million of various seismic and drilling capital expenditures. In
addition, the Company's commitment to perform 1,400 work units related to an
exploration program within the Chaco Block in Bolivia was fulfilled during 1998
through acquisitions of 3-D seismic and the drilling of two wells. Under the
Company's exploration contract on Block 19 in Ecuador, the Company is required
to participate in the drilling of one additional well. The Company expects to
drill the well during 1999 at a cost of approximately $4.0 million.
The Company is also committed to spend approximately $11.0 million in the
Republic of Yemen over a two and one-half year period which began in July 1998.
The expenditures will include the acquisition and interpretation of 150
square kilometers of seismic and the drilling of three exploration wells. At
the end of the first two and one-half years, the Company has the option to
extend the work program for a second two and one-half year period with similar
work and capital commitments required.
Except for the commitments discussed above, 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 and anticipates that its cash
flow, net of debt service obligations, coupled with advances under its revolving
credit facility, will be sufficient to fund its planned $185 million of non-
acquisition capital expenditures during 1998. The Company's planned 1998 non-
acquisition capital expenditure budget is allocated approximately 60 percent to
exploitation activities, including development and infill drilling, and
approximately 40 percent to exploration activities. In addition, the Company
recently announced a preliminary capital budget for 1999 of $115 million,
exclusive of acquisitions. The Company does not have a specific acquisition
budget since the timing and size of acquisitions are difficult to forecast. The
Company is actively pursuing additional acquisitions of oil and gas properties.
In addition to internally generated cash flow and advances under its revolving
credit facility, the Company may seek additional sources of capital to fund any
future significant acquisitions (see "--Liquidity").
-20-
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. In
conjunction with the purchase of substantial oil and gas assets in 1990, 1992
and 1995, the Company completed three public equity offerings, as well as a
public debt offering in 1995, which provided the Company with aggregate net
proceeds of approximately $272 million.
On February 5, 1997, the Company completed a public offering of 3,000,000
shares (after giving effect to the Company's two-for-one common stock split
effected on October 7, 1997) of common stock, all of which were sold by the
Company. Net proceeds to the Company of approximately $47 million were used to
repay a portion of existing indebtedness under the revolving credit facility.
Concurrently with the common stock offering, the Company issued $100 million of
its 8 5/8% Senior Subordinated Notes Due 2009. Net proceeds to the Company of
approximately $96 million were used to repay a portion of existing indebtedness
under the revolving credit facility.
The Company's unsecured revolving credit facility under the Amended and
Restated Credit Agreement dated October 21, 1998 (the "Credit Agreement"),
establishes a borrowing base (currently $550 million including the impact of the
Western Acquisition and the Texaco Acquisition) determined by the banks'
evaluation of the Company's oil and gas reserves.
Outstanding advances under the Credit Agreement 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 November 4, 1998, the Company had
elected a fixed rate based on LIBOR for a substantial portion of its outstanding
advances, which resulted in an average interest rate of approximately 6.5
percent per annum. In addition, the Company must pay a commitment fee ranging
from 0.25 to 0.375 percent per annum on the unused portion of the banks'
commitment.
-21-
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. Any principal advances outstanding under the
Credit Agreement at September 11, 2001, will be payable in 8 equal consecutive
quarterly installments commencing December 1, 2001, with final maturity at
September 11, 2003.
At November 10, 1998, the unused portion of the Credit Agreement was
approximately $115 million based on the current borrowing base established in
October 1998. The unused portion of the Credit Agreement 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 properties are added to the borrowing base, the banks'
determination of the borrowing base and their commitments may be increased. The
impact of continued lower oil and gas prices on the banks' next borrowing base
determination is unknown at this time.
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. For the first
nine months of 1998, approximately 67 percent of the Company's production was
oil. Realized oil prices for the period decreased by 34 percent as compared to
the same period in 1997. As a result, although total production on a BOE basis
increased by 10 percent, the Company's earnings and cash flows have been
materially reduced compared to 1997. The Company believes that its cash flows
and unused availability under the Credit Agreement are sufficient to fund its
planned capital expenditures for the foreseeable future. However, a continuation
of low oil prices may adversely affect the Company's cash flows, borrowing base
and other loan covenants to the extent that planned capital expenditures,
dividends, and other disbursements may be reduced.
INFLATION
In recent years inflation has not had a significant impact on the Company's
operations or financial condition.
INCOME TAXES
The Company incurred a current benefit for income taxes of approximately
$0.6 million for the first nine months of 1998 and a current provision of $3.3
million for the first nine months of 1997. 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
subsidiary, Vintage Petroleum Boliviana, Ltd., are subject to Bolivia income
taxes. Earnings of the Company's foreign subsidiary, Vintage Oil Argentina,
Inc., are subject to Argentina income taxes.
As of December 31, 1997, the Company had estimated net operating loss
carryforwards of $35.4 million for Argentina income tax reporting purposes which
can be used to offset future taxable income in Argentina. The carryforward
amount includes certain Argentina net operating loss carryforwards which were
acquired in a purchase business combination and are recorded at cost, which is
less than the calculated value under the provisions of Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes. These unrecorded net
operating loss carryforwards will reduce the Company's foreign income tax
provision for financial purposes in future years by approximately $4.5 million
when their benefit is realized. 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.
The Company has a U.S. Federal alternative minimum tax ("AMT") credit
carryforward of approximately $2.9 million which does not expire and is
available to offset U.S. Federal regular income taxes in future years, but only
to the extent that U.S. Federal regular income taxes exceed the AMT in such
years. The Company expects to incur a tax net operating loss ("NOL") for U.S.
purposes in 1998 and will be able to carry back the NOL two years and/or forward
20 years to receive a refund of prior income taxes paid or to offset future
income taxes to be paid.
-22-
FOREIGN OPERATIONS
A significant portion of the Company's foreign operations are located in
Argentina. The Company believes Argentina offers a relatively stable political
environment and does not anticipate any significant change in the near future.
The current democratic form of the government has been in place since 1983 and,
since 1989, has pursued a steady process of privatization, deregulation and
economic stabilization and reforms involving the reduction of inflation and
public spending. Argentina's 12-month trailing inflation rate measured by the
Argentine Consumer Price Index declined from 200.7 percent as of June 1991 to a
negative 4.04 percent (-4.04%) as of September 1998.
The Company believes that its Argentine operations present minimal currency
risk. 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 Argentina
Central Bank is obligated by law to sell dollars at a rate of one Argentine peso
to one U.S. dollar and has sought to prevent appreciation of the peso by buying
dollars at rates of not less than 0.998 peso to one U.S. dollar. As a result,
the Company believes that should any devaluation of the Argentine peso occur its
revenues would be unaffected and its operating costs would not be significantly
increased. 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.
On February 1, 1987, a new currency, 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, 1998, was
US$1:Bs5.58. 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.
YEAR 2000
The Year 2000 issue represents a potentially serious information systems
problem because many software applications and operational systems written in
the past may not properly recognize calendar dates beginning in the Year 2000.
This problem could force computers to either shut down or provide incorrect data
or information. In consultation with its software and hardware providers, the
Company began the process of identifying the changes required to its major
financial/administrative systems and hardware in early 1997. Software upgrades
designed to correct the Year 2000 issue for its U.S. financial systems were
implemented in mid-1998 and testing is scheduled for completion by year-end
1998. A replacement financial system has been selected for the Company's
international locations and implementation has commenced in Bolivia with
conversion of other international locations scheduled prior to April 1, 1999.
-23-
The Company is currently in the process of assessing the potential impact
that the Year 2000 issue will have on its field operating equipment and systems
and has not yet completed its evaluation of the impact that the Year 2000 issue
will have on such equipment and systems. In addition, the Company is also
uncertain how it will be indirectly affected by the impact that the Year 2000
issue will have on the companies with which it conducts business. The Company
does not believe that costs to address the Year 2000 issue will have a material
adverse impact on its business, financial condition or results of operation.
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 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.
-24-
PART II
OTHER INFORMATION
-25-
Item 1. Legal Proceedings
For information regarding legal proceedings, see the Company's Form 10-
K for the year ended December 31, 1997.
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
The Company recently announced that it had acquired producing oil and
gas properties in three separate transactions involving both asset
purchases and a stock purchase. (See Note 4 to the consolidated
financial statements included herein.) The Company estimates that 35.9
million barrels of oil equivalent ("BOE") were acquired in these three
transactions for an aggregate cost attributable to oil and gas assets
of $103.9 million, for an average cost of $2.90 per BOE.
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 Amended and Restated Credit Agreement dated as of October
21, 1998, among Vintage Petroleum, Inc., as the Borrower,
and Certain Commercial Lending Institutions, as the
Lenders, Bank of Montreal, acting through certain U.S.
branches or agencies, as administrative agent,
NationsBank, N.A., as syndication agent, and Societe
Generale, Southwest Agency, as documentation agent.
27 Financial Data Schedule.
-26-
b) Reports on Form 8-K
Form 8-K was filed August 18, 1998, to report under Item 5 the
restatement of the Company's financial statements and notes
thereto, management's discussion and analysis of financial
condition and results of operations, and summary financial and
operating data for the years ended December 31, 1997, 1996 and
1995, previously reported in the Company's 1997 annual report
and selected financial information for the three months ended
March 31, 1998, previously reported in the Company's March 31,
1998, Form 10-Q as a result of the Company's election to change
its accounting method for oil and gas properties from the full
cost method to the successful efforts method effective January
1, 1998.
********************************************************************************
-27-
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
VINTAGE PETROLEUM, INC.
-----------------------
(Registrant)
DATE: November 13, 1998 \s\ Michael F. Meimerstorf
------------------ -----------------------------------
Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)
-28-
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 Amended and Restated Credit Agreement dated as of October 21, 1998,
among Vintage Petroleum, Inc., as the Borrower, and Certain
Commercial Lending Institutions, as the Lenders, Bank of Montreal,
acting through certain U.S. branches or agencies, as administrative
agent, NationsBank, N.A., as syndication agent, and Societe
Generale, Southwest Agency, as documentation agent.
27 Financial Data Schedule.