<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
[ X ] OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
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 (Zip Code)
executive offices)
(918) 592-0101
------------------------------------------------------
(Registrant's telephone number, including area code)
NOT APPLICABLE
--------------------------------------------------------------------------
(Former name, former address and former fiscal year, if changed since
last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No _____
-----
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
Class Outstanding at November 3, 1999
- ----------------------------- -------------------------------
Common Stock, $.005 Par Value 62,407,866
-1-
<PAGE>
PART I
FINANCIAL INFORMATION
-2-
<PAGE>
ITEM 1. FINANCIAL STATEMENTS
-----------------------------
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------
(In thousands, except shares
and per share amounts)
(Unaudited)
ASSETS
------
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------- -----------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 5,935 $ 5,245
Accounts receivable -
Oil and gas sales 76,710 54,680
Joint operations 4,459 5,905
Prepaids and other current assets 23,278 18,312
------------- -----------
Total current assets 110,382 84,142
------------- -----------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method 1,505,369 1,368,914
Oil and gas gathering systems 15,395 14,774
Other 16,786 16,276
------------- -----------
1,537,550 1,399,964
Less accumulated depreciation, depletion and amortization 563,732 501,722
------------- -----------
973,818 898,242
------------ -----------
DEFERRED INCOME TAXES 8,356 2,505
------------- -----------
OTHER ASSETS, net 32,519 29,286
------------- -----------
TOTAL ASSETS $ 1,125,075 $ 1,014,175
============= ===========
</TABLE>
See notes to unaudited consolidated financial statements.
-3-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
CURRENT LIABILITIES:
Revenue payable $ 21,079 $ 17,382
Accounts payable - trade 22,153 24,812
Deferred acquisition costs payable 18,850 -
Other payables and accrued liabilities 38,584 24,731
------------- ------------
Total current liabilities 100,666 66,925
------------- ------------
LONG-TERM DEBT 652,190 672,507
------------- ------------
OTHER LONG-TERM LIABILITIES 476 785
------------- ------------
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,
62,347,866 and 53,107,066 shares issued and
outstanding, respectively 312 266
Capital in excess of par value 314,135 230,736
Retained earnings 57,296 42,956
------------- ------------
371,743 273,958
------------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,125,075 $ 1,014,175
============= ============
</TABLE>
See notes to unaudited consolidated financial statements.
-4-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
---------------------------------
(In thousands, except per share amounts)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales $113,580 $ 64,915 $240,902 $206,584
Gas marketing 16,404 12,593 38,905 39,664
Oil and gas gathering 1,734 1,476 5,184 6,811
Other income 4,711 301 10,003 1,152
--------- --------- --------- ---------
136,429 79,285 294,994 254,211
--------- --------- --------- ---------
COSTS AND EXPENSES:
Lease operating, including production taxes 31,886 29,487 80,991 91,693
Exploration costs 1,322 6,569 9,523 18,939
Gas marketing 15,705 12,061 37,095 37,701
Oil and gas gathering 1,311 1,334 3,932 5,851
General and administrative 8,413 7,825 24,482 23,922
Depreciation, depletion and amortization 26,231 26,797 83,240 80,283
Interest 15,185 11,525 44,321 30,795
--------- --------- --------- ---------
100,053 95,598 283,584 289,184
--------- --------- --------- ---------
Income (loss) before income taxes taxes 36,376 (16,313) 11,410 (34,973)
PROVISION (BENEFIT) FOR INCOME TAXES:
Current 2,749 (125) 2,796 (586)
Deferred 6,349 (6,263) (5,726) (13,372)
--------- --------- --------- ---------
NET INCOME (LOSS) $ 27,278 $ (9,925) $ 14,340 $(21,015)
========= ========= ========= =========
EARNINGS (LOSS) PER SHARE:
Basic $.44 $(.19) $.25 $(.41)
========= ========= ========= =========
Diluted $.43 $(.19) $.25 $(.41)
========= ========= ========= =========
Weighted average common shares outstanding:
Basic 62,309 51,733 56,505 51,664
========= ========= ========= =========
Diluted 64,143 51,733 57,869 51,664
========= ========= ========= =========
</TABLE>
See notes to unaudited consolidated financial statements.
-5-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
---------------------------------------------------------
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
--------------------------------------------
(In thousands)
(Unaudited)
<TABLE>
<CAPTION>
Capital
In Excess
Common Stock of Par Retained
------------------
Shares Amount Value Earnings Total
------- -------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Balance at December 31, 1998 53,107 $ 266 $ 230,736 $ 42,956 $ 273,958
Net income - - - 14,340 14,340
Issuance of common stock 9,241 46 83,284 - 83,330
Tax effect of stock option exercises - - 115 - 115
------- -------- --------- ---------- ---------
Balance at September 30, 1999 62,348 $ 312 $ 314,135 $ 57,296 $ 371,743
======= ======== ========= ========== =========
</TABLE>
-6-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(In thousands)
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
---------------------
1999 1998
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 14,340 $ (21,015)
Adjustments to reconcile net income (loss) to
cash provided by operating activities -
Depreciation, depletion and amortization 83,240 80,283
Exploration costs 9,523 18,939
Benefit for deferred income taxes (5,726) (13,372)
Gain on property sales (7,671) -
--------- ---------
93,706 64,835
(Increase) decrease in receivables (20,584) 10,184
Increase (decrease) in payables and accrued liabilities 16,343 (13,971)
Other (4,898) (4,062)
--------- ---------
Cash provided by operating activities 84,567 56,986
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment -
Oil and gas properties (150,037) (152,532)
Other property and equipment (1,491) (4,408)
Proceeds from sales of oil and gas properties 9,715 -
Other 458 (3,245)
--------- ---------
Cash used by investing activities (141,355) (160,185)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock 83,330 879
Sale of 9 3/4% Senior Subordinated Notes 146,000 -
Advances on revolving credit facility and other borrowings 29,837 123,651
Payments on revolving credit facility and other borrowings (200,361) (16,515)
Dividends paid (1,328) (4,392)
Other - (3,665)
--------- ---------
Cash provided by financing activities 57,478 99,958
--------- ---------
Net increase (decrease) in cash and cash equivalents 690 (3,241)
Cash and cash equivalents, beginning of period 5,245 5,797
--------- ---------
Cash and cash equivalents, end of period $ 5,935 $ 2,556
========= =========
</TABLE>
See notes to unaudited consolidated financial statements.
-7-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
September 30, 1999 and 1998
1. GENERAL
The accompanying financial statements are unaudited. The consolidated
financial statements include the accounts of the Company and its wholly- and
majority-owned subsidiaries. In addition, the Company's interests in various
joint ventures have been proportionately consolidated, whereby the Company's
proportionate share of each joint venture's assets, liabilities, revenues and
expenses is included in the appropriate accounts in the consolidated financial
statements. 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. These financial statements and notes should be
read in conjunction with the 1998 audited financial statements and related
notes. Certain reclassifications have been made to the prior year financial
statements to conform to the 1999 presentations. These reclassifications had no
effect on previously reported net income or cash flow.
2. SIGNIFICANT ACCOUNTING POLICIES
Change in Accounting Method
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 of
accounting is preferable and that the accounting change will more accurately
present the results of the Company's exploration and development activities,
minimize asset write-offs caused by temporary declines in oil and gas prices and
reflect 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
a result of this change in accounting, all previously reported financial
statements have been retroactively restated to give effect to this change in
accounting method.
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. If oil
and gas prices decline in the future, some of these unproved prospects may not
be economic to develop which could lead to increased impairment expense.
-8-
<PAGE>
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.
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 oil and gas reserves over
the economic life of the reserves, based on the Company's expectations of future
oil and gas prices and costs. No impairment provision was required for the first
nine months of either 1999 or 1998. 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.
Statements of Cash Flows
Cash payments for interest totaled $36,454,628 and $28,985,776 for the
nine months ended September 30, 1999 and 1998, respectively. Cash payments for
U.S. Federal and state income taxes were $1,473,252 during the nine months ended
September 30, 1998. There were no cash payments made for U.S. income taxes in
the first nine months of 1999. During the nine months ended September 30, 1999
and 1998, the Company made cash payments of $62,671 and $1,256,041,
respectively, for foreign taxes.
Earnings Per Share
The Company applies Financial Accounting Standards Board Statement No. 128,
Earnings Per Share ("SFAS No. 128"). Basic earnings (loss) per common share were
computed by dividing net income (loss) by the weighted average number of shares
outstanding during the period. For the nine months ended September 30, 1998, and
for the three months ended September 30, 1998, the computation of diluted loss
per share was antidilutive; therefore, the amounts reported for basic and
diluted loss per share were the same. Had the Company been in a net income
position for these periods, the Company's diluted weighted average outstanding
common shares as calculated under SFAS No. 128 would have been 52,718,463 and
52,443,546, respectively. In addition, for the nine months ended September 30,
1999 and 1998, and for the three months ended September 30, 1999 and 1998, the
Company had outstanding stock options for 1,825,000, 829,000, 1,633,000 and
1,629,000 additional shares of the Company's common stock, respectively, with
average exercise prices of $17.04, $20.08, $17.82 and $17.83, respectively,
which were antidilutive.
-9-
<PAGE>
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.
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. During the nine month periods ended
September 30, 1999 and 1998, the Company had no non-owner changes in equity
other than net income or loss.
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 an adjustment to sales revenue when the related transactions
being hedged are finalized. Gains or losses from swap agreements that do not
qualify for accounting treatment as hedges are recognized currently as other
income or expense. The cash flows from such agreements are included in operating
activities in the consolidated statements of cash flows.
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"). In June 1999, the FASB
issued Statement No. 137, Accounting for Derivative Instruments and Hedging
Activities-Deferral of the Effective Date of FASB Statement 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.
SFAS No. 133, as amended, is effective for fiscal years beginning after
June 15, 2000; however, beginning June 16, 1998, companies may implement the
statement as of the beginning of any fiscal quarter. SFAS No. 133 cannot be
applied retroactively and must be applied to (a) derivative instruments and (b)
certain derivative instruments embedded in hybrid contracts. 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.
-10-
<PAGE>
3. CAPITAL STOCK
On March 17, 1999, the Company's Board of Directors adopted a stockholder
rights plan and declared a dividend distribution of one Preferred Share Purchase
Right on each outstanding share of its common stock which was made on April 5,
1999, to stockholders of record on that date. The Rights will expire on April 5,
2009.
The Rights will be exercisable only if a person or group acquires 15
percent or more of the Company's common stock or announces a tender offer the
consummation of which would result in ownership by a person or group of 15
percent or more of the common stock. Each Right will entitle stockholders to buy
one one-thousandth of a share of a new series of junior participating preferred
stock at an exercise price of $60. If the Company is acquired in a merger or
other business combination transaction after a person has acquired 15 percent or
more of the Company's outstanding common stock, each Right will entitle its
holder to purchase, at the Right's then-current exercise price, a number of the
acquiring company's common shares having a market value of twice such price. In
addition, if a person or group acquires 15 percent or more of the Company's
outstanding common stock, each Right will entitle its holder (other than such
person or members of such group) to purchase, at the Right's then-current
exercise price, a number of the Company's common shares having a market value of
twice such price. Prior to the acquisition by a person or group of beneficial
ownership of 15 percent or more of the Company's common stock, the Rights are
redeemable for one cent per Right at the option of the Company's Board of
Directors.
On June 21, 1999, the Company completed a public offering of 9,000,000
shares of common stock, all of which were sold by the Company. Net proceeds of
approximately $81.2 million were used to partially fund the purchase of certain
oil and gas properties from a subsidiary of Total Fina S.A. and a subsidiary of
Repsol S.A. in early July 1999. On July 15, 1999, in connection with the
exercise by the underwriters of a portion of the over-allotment option, the
Company sold an additional 240,800 shares of common stock using the additional
$2.1 million of net proceeds to reduce a portion of the Company's existing
indebtedness under its revolving credit facility.
4. SEGMENT INFORMATION
The Company adopted Statement of Financial Accounting Standards No. 131,
Disclosures About Segments of an Enterprise and Related Information, in 1998
which changes the way the Company reports information about its operating
segments.
The Company's reportable business segments have been identified based on
the differences in products or services provided. Revenues for the exploration
and production segment are derived from the production and sale of natural gas
and crude oil. Revenues for the gathering segment arise from the transportation
and sale of natural gas and crude oil. 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.
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<PAGE>
Operations in the gathering and gas marketing industries are in the
United States. The Company operates in the oil and gas exploration and
production industry in the United States, South America and in Yemen beginning
in 1998. Summarized financial information for the Company's reportable segments
for the first nine months and third quarters of 1999 and 1998 is shown in the
following table:
<TABLE>
<CAPTION>
Exploration and Production
------------------------------------------
Other Gas
U.S. Argentina Foreign Gathering Marketing Corporate Total
----------- ----------- ---------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Nine months ended 9/30/99
- ----------------------------------
Revenues from external customers.. $ 157,396 $ 86,047 $ 7,034 $ 5,184 $ 38,905 $ 428 $ 294,994
Intersegment revenues............. - - - 951 949 - 1,900
Depreciation, depletion and
amortization expense........ 56,257 21,547 2,339 1,043 - 2,054 83,240
Operating income (loss)........... 38,969 43,064 (2,212) 209 1,810 (1,628) 80,212
Total assets...................... 523,472 378,882 129,591 7,388 12,307 73,435 1,125,075
Capital investments............... 15,239 125,319 28,329 621 - 870 170,378
Long-lived assets................. 493,036 351,321 121,702 3,928 - 3,831 973,818
Nine months ended 9/30/98
- ----------------------------------
Revenues from external customers.. $ 150,774 $ 51,853 $ 4,428 $ 6,811 $ 39,664 $ 681 $ 254,211
Intersegment revenues............. - - - 568 1,106 - 1,674
Depreciation, depletion and
amortization expense........ 55,636 19,290 2,320 1,365 - 1,672 80,283
Operating income (loss)........... 8,689 11,841 (1,352) (405) 1,963 (992) 19,744
Total assets...................... 578,380 255,238 64,730 7,658 10,143 48,625 964,774
Capital investments............... 92,544 38,212 21,775 1,521 - 2,887 156,939
Long-lived assets................. 547,771 246,753 59,798 4,368 - 6,037 864,727
Three months ended 9/30/99
- ----------------------------------
Revenues from external customers.. $ 65,147 $ 49,155 $ 3,722 $ 1,734 $ 16,404 $ 267 $ 136,429
Intersegment revenues............. - - - 301 375 - 676
Depreciation, depletion and
amortization expense........ 15,383 8,666 1,001 349 - 832 26,231
Operating income (loss)........... 28,494 29,812 1,573 74 699 (679) 59,973
Capital investments............... 6,077 124,258 7,349 32 - 535 138,251
Three months ended 9/30/98
- ----------------------------------
Revenues from external customers.. $ 47,570 $ 16,197 $ 1,306 $ 1,476 $ 12,593 $ 143 $ 79,285
Intersegment revenues............. - - - 117 339 - 456
Depreciation, depletion and
amortization expense........ 18,269 6,505 784 494 - 745 26,797
Operating income (loss)........... 258 3,196 3 (351) 532 (602) 3,036
Capital investments............... 26,059 10,371 5,562 662 - 513 43,167
</TABLE>
Intersegment sales are priced in accordance with terms of existing
contracts and current market conditions. Capital investments include expensed
exploratory costs. Corporate general and administrative costs and interest costs
are not allocated to the operating income (loss) of the segments.
-12-
<PAGE>
5. COMMITMENTS
During April 1999, the Company entered into a new lease agreement for its
corporate headquarters. The future minimum commitments under all of the
Company's long-term non-cancellable leases for office space, including this new
agreement, for the remaining three months of 1999 and the calendar years of 2000
through 2004 are $0.3 million, $1.4 million, $1.3 million, $1.4 million, $1.4
million and $1.5 million, respectively, with $3.7 million remaining in years
thereafter.
During July 1999, the Company also committed to perform an additional
1,068 work units in its Chaco field in Bolivia over the next two years. This
work commitment is secured by a $5.3 million letter of credit.
-13-
<PAGE>
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:
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
1999 1998 1999 1998
-------- -------- --------- ---------
<S> <C> <C> <C> <C>
Production:
Oil (MBbls) -
U.S..................................... 2,183 2,500 6,484 7,509
Argentina............................... 2,287 1,552 5,330 4,637
Ecuador................................. 138 - 381 -
Bolivia................................. 28 30 58 99
Total................................... 4,636 4,082 12,253 12,245
Gas (MMcf) -
U.S..................................... 9,577 10,386 29,010 31,530
Bolivia................................. 1,817 1,372 3,345 4,036
Argentina............................... 2,547 - 2,921 -
Total................................... 13,941 11,758 35,276 35,566
Total MBOE.................................. 6,959 6,042 18,132 18,172
Average prices:
Oil (per Bbl) -
U.S..................................... $ 17.50 (a) $ 11.08 $ 14.01 (a) $ 11.64
Argentina............................... 19.72 10.43 15.32 11.18
Ecuador................................. 14.28 - 10.74 -
Bolivia................................. 16.95 10.24 14.53 11.49
Total................................... 18.50 (a) 10.83 14.48 (a) 11.46
Gas (per Mcf) -
U.S..................................... $ 2.41 $ 1.90 $ 1.98 $ 2.00
Bolivia................................. .70 .73 .63 .81
Argentina............................... 1.37 - 1.32 -
Total................................... 2.00 1.76 1.80 1.86
</TABLE>
(a) Includes the impact of hedging activities.
-14-
<PAGE>
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 26 percent increase in its average oil
price in the first nine months of 1999 compared to the first nine months of 1998
and a 71 percent increase in the third quarter of 1999 compared to the same
period of 1998. The Company realized an average oil price (before the impact of
hedges) for the third quarter of 1999 which was approximately 99 percent of WTI
posted prices compared to a realization of 93 percent of WTI posted prices for
the year-earlier third quarter. The Company's average realized oil price
(before the impact of hedges) increased to 86 percent of the NYMEX reference
price ("NYMEX") in the third quarter of 1999 compared to 77 percent of NYMEX in
the year-earlier period.
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. The
Company's Argentina average gas price is tied to a long-term contract under
which the base price is tied to the NYMEX reference price for oil. The
Company's overall average gas price for the first nine months of 1999 was three
percent lower than 1998's first nine months; however, its overall average gas
price for the third quarter of 1999 was 14 percent higher than the same period
of 1998.
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 had no hedging
agreements in place covering 1998 oil or gas production. The Company has
various natural gas basis swaps in place for the last three months of 1999
covering a total of 82,000 MMBtu of gas per day plus an additional 3,000 MMBtu
per day for the month of October 1999. The natural gas basis swaps were used to
reduce the Company's exposure to increases in the basis differential between the
NYMEX reference price and the Company's industry delivery point indexes under
which the gas is sold. During the first nine months of 1999, the Company's
overall and U.S. average gas prices were each reduced by two cents and three
cents, respectively, as a result of these swaps. The Company's overall and U.S.
average gas prices for the third quarter of 1999 were each increased by one cent
as a result of the swaps.
The Company's overall and U.S. average oil prices for the first nine months of
1999 were decreased by eight cents and 15 cents, respectively, as a result of
oil hedges. The Company's overall and U.S. average oil prices for the third
quarter of 1999 were decreased by 27 cents and 57 cents, respectively, as a
result of oil hedges. The Company currently has no oil hedges in place.
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 1999 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 $3.3 million and $4.5 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 $0.9 million and $1.4 million, respectively, based on third
quarter 1999 gas production.
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<PAGE>
Period to Period Comparison
Three months ended September 30, 1999, Compared to three months ended September
30, 1998
The Company reported net income of $27.3 million for the quarter ended
September 30, 1999, compared to a net loss of $9.9 million for the year-earlier
quarter. The increase in the Company's net income is primarily due to the 71
percent increase in average oil prices and a 14 percent increase in average gas
prices coupled with a 15 percent increase in production on an equivalent barrel
basis. These gains were partially offset by a $3.7 million increase in interest
expense and a $2.4 million increase in lease operating expenses.
Oil and gas sales increased $48.7 million (75 percent), to $113.6 million for
the third quarter of 1999 from $64.9 million for the third quarter of 1998. A
71 percent increase in average oil prices, coupled with a 14 percent increase in
oil production, accounted for an increase in oil sales of $41.6 million. A 14
percent increase in average gas prices, coupled with a 19 percent increase in
gas production, accounted for a $7.1 million increase in gas sales for the 1999
third quarter as compared to the year-earlier quarter. The 14 percent increase
in oil production and the 19 percent increase in gas production are primarily
the result of the acquisition of the El Huemul concession in Argentina in July
1999.
Other income increased $4.4 million (1,467 percent), to $4.7 million for the
third quarter of 1999 from $0.3 million for the third quarter of 1998. The
increase is primarily the result of the recognition of gains of $3.3 million
resulting from the sales of certain non-strategic oil and gas properties during
the third quarter of 1999.
Lease operating expenses, including production taxes, increased $2.4 million
(8 percent), to $31.9 million for the third quarter of 1999 from $29.5 million
for the third quarter of 1998. The increase in lease operating expenses is due
to the acquisition of the El Huemul concession in Argentina in July of 1999.
The additional costs as a result of El Huemul were partially offset by cost
reductions resulting from the rebidding of certain operating services and
supplies and the restructuring of certain domestic field operations which began
in late 1998. As a result of the 15 percent increase in production on an
equivalent barrel basis and the Company's cost reduction efforts, lease
operating expenses per equivalent barrel produced decreased six percent to $4.58
in the third quarter of 1999 from $4.88 for the same period in 1998.
Exploration costs decreased $5.2 million (80 percent), to $1.3 million for the
third quarter of 1999 from $6.6 million for same period of 1998. During the
third quarter of 1999, the Company's exploration costs included $0.7 million for
unsuccessful exploratory drilling and lease impairments and $0.6 million for 3-D
seismic data and other geological and geophysical costs. The Company's 1998
third quarter exploration costs consisted primarily of $2.8 million in 3-D
seismic acquisition costs primarily in the U.S. Gulf Coast area and Bolivia,
$2.2 million in unsuccessful exploratory drilling, $1.2 million for lease
expirations and $0.4 million in other geological and geophysical costs.
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<PAGE>
General and administrative expenses increased $0.6 million (8 percent), to
$8.4 million for the third quarter of 1999 from $7.8 million for the third
quarter of 1998 due partially to costs incurred relating to Year 2000 readiness
and the additional costs associated with the acquisition of the Company's
Ecuadorian subsidiary, Elf Hydrocarbures Equateur ("Elf Ecuador"), from Elf
Aquitaine in November 1998 and the establishment of an office in Yemen in mid-
1998 to support the exploration efforts begun there in late 1997. Despite the
eight percent increase in costs, general and administrative expenses per
equivalent barrel produced for the third quarter of 1999 decreased to $1.21 from
the $1.30 seen in the prior-year quarter as a result of the 15 percent increase
in the Company's oil and gas production.
Depreciation, depletion and amortization ("DD&A") decreased $0.6 million (2
percent), to $26.2 million for the third quarter of 1999 from $26.8 million for
the third quarter of 1998, due to the 15 percent decrease in the Company's
average amortization rate per equivalent barrel produced which more than offset
the 15 percent increase in the Company's oil and gas production for the third
quarter of 1999. The average amortization rate per equivalent barrel of the
Company's oil and gas properties decreased from $4.23 in the third quarter of
1998 to $3.58 in the third quarter of 1999 primarily as a result of the impact
of the new production from the Company's El Huemul and Naranjillos concessions
which have substantially lower amortization rates.
Interest expense increased $3.7 million (32 percent), to $15.2 million for the
third quarter of 1999 from $11.5 million for the third quarter of 1998, due
primarily to a 24 percent increase in the Company's total average outstanding
debt as a result of the Company's 1998 total capital spending, including
acquisitions, in excess of 1998's cash flow and the increase in the Company's
overall average interest rate to 8.33% in the third quarter of 1999 as compared
to 7.74% in the third quarter of 1998. The Company had $12.3 million and $5.3
million of accrued interest payable at September 30, 1999, and December 31,
1998, respectively, included in other payables and accrued liabilities.
Nine months ended September 30, 1999, Compared to nine months ended September
30, 1998
The Company reported net income of $14.3 million for the nine months ended
September 30, 1999, compared to a net loss of $21.0 million for the year-earlier
period. The increase in the Company's net income is primarily due to a 26
percent increase in average oil prices, a 12 percent decrease in lease operating
costs, the recognition of $7.7 million in gains related to the sales of non-
strategic oil and gas properties and a 50 percent decrease in exploration costs.
These items were partially offset by a 44 percent increase in interest expense,
a four percent increase in DD&A and a three percent decrease in average gas
prices.
Oil and gas sales increased $34.3 million (17 percent), to $240.9 million for
the first nine months of 1999 from $206.6 million for the nine months of 1998.
A 26 percent increase in average oil prices primarily accounted for the $34.3
million increase in oil and gas sales for the first nine months of 1999 as
compared to the year-earlier period.
Other income increased $8.8 million (733 percent), to $10.0 million for the
first nine months of 1999 from $1.2 million for the first nine months of 1998.
The increase is primarily the result of the recognition of gains of $7.7 million
resulting from the sales of certain non-strategic oil and gas properties during
the first nine months of 1999.
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<PAGE>
Lease operating expenses, including production taxes, decreased $10.7 million
(12 percent), to $81.0 million for the first nine months of 1999 from $91.7
million for the first nine months of 1998. The decrease in lease operating
expenses is due primarily to operating cost reductions resulting from the
shutting-in of certain oil properties for a portion of the period as a result of
historically low oil prices, the rebidding of certain operating services and
supplies and the restructuring of certain field operations. These cost savings
seen in 1999 were partially offset by the additional lease operating costs
associated with the El Huemul concession in Argentina acquired in early July
1999. In addition, the first nine months of 1998 included lease operating costs
of approximately $2.2 million relating to the storm damage clean up and repairs
required as a result of severe weather in California and the Gulf of Mexico; no
similar charges were incurred in 1999. Primarily as a result of the Company's
cost reduction efforts, lease operating expenses per equivalent barrel produced
decreased 11 percent to $4.47 in the first nine months of 1999 from $5.05 for
the same period in 1998.
Exploration costs decreased $9.4 million (50 percent), to $9.5 million for the
first nine months of 1999 from $18.9 million for same period of 1998. During the
first nine months of 1999, the Company's exploration costs included $5.2 million
for the acquisition of 3-D seismic data primarily in Yemen and western Oklahoma,
$3.1 million for unsuccessful exploratory drilling and lease impairments and
$1.2 million in other geological and geophysical costs. The Company's 1998 first
nine months exploration costs consisted primarily of $12.8 million in 3-D
seismic acquisition costs primarily in the U.S. Gulf Coast area and Bolivia,
$2.7 million in unsuccessful exploratory drilling, $1.9 million in lease
expirations and $1.5 million in other geological and geophysical costs.
General and administrative expenses increased $0.6 million (3 percent) to
$24.5 million for the first nine months of 1999 from $23.9 million for the first
nine months of 1998. Additional costs associated with the acquisition of Elf
Ecuador in November 1998 and the establishment of an office in Yemen in mid-1998
to support the exploration efforts begun there in late 1997 and costs related to
Year 2000 readiness were primarily offset as a result of the Company's cost
cutting efforts during 1999. General and administrative expenses per equivalent
barrel produced increased to $1.35 from $1.32 in the year-earlier first nine
months.
Depreciation, depletion and amortization increased $2.9 million (4 percent),
to $83.2 million for the first nine months of 1999 from $80.3 million for the
first nine months of 1998, due primarily to the four percent increase in the
average amortization rate per equivalent barrel of the Company's oil and gas
properties from $4.25 in the first nine months of 1998 to $4.41 in 1999. This
increase was primarily a result of the dramatic impact that historically low oil
and gas prices had on the Company's December 31, 1998, proved oil and gas
reserves used to calculate its first quarter DD&A.
Interest expense increased $13.5 million (44 percent), to $44.3 million for
the first nine months of 1999 from $30.8 million for the first nine months of
1998, due primarily to a 36 percent increase in the Company's total average
outstanding debt as a result of the Company's 1998 total capital spending,
including acquisitions, in excess of 1998's cash flow and an increase in the
Company's overall average interest rate to 8.04% in the first nine months of
1999 from 7.80% in the first nine months of 1998.
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<PAGE>
Capital Expenditures
During the first nine months of 1999, the Company's domestic oil and gas
capital expenditures totaled $15.2 million. Exploratory activities accounted for
$6.8 million of these expenditures with exploitation activities contributing
another $6.4 million. The $2.0 million balance of the domestic capital
expenditures relates to the acquisition of certain additional interests in
Company operated oil and gas properties and gathering system additions. During
the first nine months of 1999, the Company's international oil and gas capital
expenditures totaled $153.6 million, including $22.1 million and $5.2 million in
Bolivia and Yemen, respectively, primarily on exploratory drilling in Bolivia
and seismic activity in Yemen. The largest of the Company's international
capital expenditures was the purchase of the El Huemul concession in Argentina
in early July for approximately $122.0 million in cash and deferred payments.
During June 1999, the Company entered into a definitive purchase and sale
agreement with a subsidiary of Total Fina S.A. to purchase its 70 percent
interest in certain oil and gas properties located in the San Jorge basin's El
Huemul concession in Argentina for $88.3 million. The Company closed the
acquisition on July 1, 1999. The Company has a deferred payment of $13.0 million
related to this acquisition due on or before December 31, 1999. Additionally, on
July 6, 1999, the Company purchased the remaining 30 percent interest in these
oil and gas properties from a subsidiary of Repsol S.A. for $33.7 million in
cash, including a deferred payment of $5.9 million due on or before January 3,
2000. The cash required for the closing of these two acquisitions was funded by
the net proceeds from the June 1999 common stock offering and advances under the
Company's revolving credit facility. The Company expects cash flow from these
properties to be sufficient to fund the $18.9 million in deferred payments.
The Company 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 total work unit commitment was guaranteed by the Company through an
$88.6 million letter of credit; however, the Company anticipated that it would
fulfill this three-year work unit commitment through approximately $60 million
of various seismic and drilling capital expenditures. During 1998, the Company
spent approximately $7.6 million toward the fulfillment of the work unit
commitment through the acquisition of seismic data and the drilling of one well.
Of the $24 million (7,500 work units) budgeted by the Company to be spent in
1999 related to the fulfillment of its Naranjillos field commitment,
approximately $18.6 million was spent during the first nine months primarily on
exploratory drilling activities. Through September 1999, the Company had
completed approximately 6,400 work units of the 17,728 work unit commitment.
During July 1999, the Company also committed to perform an additional 1,068
work units in its Chaco field located in Bolivia over the next two years. This
work commitment is secured by a $5.3 million letter of credit.
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<PAGE>
The Company is also committed to spend approximately $11 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. During 1998, approximately $0.6 million of the $11 million
commitment was spent. Of the approximately $5 million budgeted to be spent in
1999 for the acquisition of 3-D seismic data in Yemen, the Company spent
approximately $4.4 million in the first nine months of 1999.
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, coupled with advances
under its revolving credit facility, to fund capital expenditures other than
significant acquisitions and anticipates that its cash flow, net of debt service
obligations, will be sufficient to fund its revised budget of $83 million for
non-acquisition capital expenditures during 1999. The Company's planned 1999
non-acquisition capital expenditure budget is currently allocated 55 percent to
exploration activities and 45 percent to exploitation activities, including
development and infill drilling. The Company does not have a specific
acquisition budget since the timing and size of acquisitions are difficult to
forecast. The Company is actively pursuing additional acquisitions of oil and
gas properties. In addition to internally generated cash flow and advances under
its revolving credit facility, the Company may seek additional sources of
capital to fund any future significant acquisitions (see "-Liquidity"), however,
no assurance can be given that sufficient funds will be available to fund the
Company's desired acquisitions.
Liquidity
Internally generated cash flow and the borrowing capacity under its revolving
credit facility are the Company's major sources of liquidity. In addition, the
Company may use other sources of capital, including the issuance of additional
debt securities or equity securities, to fund any major acquisitions it might
secure in the future and to maintain its financial flexibility. The Company
funds its capital expenditures (excluding acquisitions) and debt service
requirements primarily through internally generated cash flows from operations.
Any excess cash flow is used to reduce outstanding advances under the revolving
credit facility.
In the past, the Company has accessed the public markets to finance
significant acquisitions and provide liquidity for its future activities. Prior
to 1999, the Company completed four public equity offerings, as well as two
public debt offerings, which provided the Company with aggregate net proceeds of
approximately $415 million.
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<PAGE>
On January 26, 1999, the Company issued $150 million of its 9 3/4% Senior
Subordinated Notes Due 2009 (the "9 3/4% Notes"). The 9 3/4% Notes are
redeemable at the option of the Company, in whole or in part, at any time on or
after February 1, 2004. In addition, prior to February 1, 2002, the Company may
redeem up to 33 1/3% of the 9 3/4% Notes with the proceeds of certain
underwritten public offerings of the Company's common stock. The 9 3/4% Notes
mature on June 30, 2009, with interest payable semiannually on June 30 and
December 30 of each year. The net proceeds to the Company from the sale of the 9
3/4% Notes (approximately $146 million) were used to repay a portion of the
existing indebtedness under the Company's revolving credit facility.
On June 21, 1999, the Company completed a public offering of 9,000,000 shares
of common stock, all of which were sold by the Company. Net proceeds of
approximately $81.2 million were used to partially fund the purchase of certain
oil and gas properties from Total and Repsol in early July 1999 (see "-Capital
Expenditures"). In July 1999, in connection with the exercise by the
underwriters of a portion of the over-allotment option, the Company sold an
additional 240,800 shares of common stock using the additional $2.1 million of
net proceeds to reduce a portion of the Company's existing indebtedness under
its revolving credit facility.
The Company's unsecured revolving credit facility under the Amended and
Restated Credit Agreement dated October 21, 1998, as amended (the "Credit
Agreement"), establishes a borrowing base (currently $400 million) determined by
the banks' evaluation of the Company's oil and gas reserves. The banks are
currently in the process of completing their semi-annual borrowing base review.
As a result of this review, the Company's Agent bank has recommended the
remaining lenders approve a $550 million borrowing base; however, no assurance
can be given that the banks will approve this new borrowing base.
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 3, 1999, 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 6.9
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.
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 eight equal
consecutive quarterly installments commencing December 1, 2001, with maturity at
September 11, 2003.
The unused portion of the Credit Agreement was approximately $134 million at
November 3, 1999. 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.
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<PAGE>
The Company's internally generated cash flow, results of operations and
financing for its operations are dependent on oil and gas prices. Although the
Company has seen significant improvements in its commodity prices during the
third quarter of 1999, should these improvements not be sustained, its earnings
and cash flow from operations will be adversely impacted. 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, lower oil and gas prices may cause the Company to not be in compliance
with maintenance covenants under its Credit Agreement and may negatively affect
its credit statistics and coverage ratios and thereby affect its liquidity.
Inflation
In recent years, U.S. inflation has not had a significant impact on the
Company's operations or financial condition. For discussion on the Company's
international operations and the impact of inflation, see the section "Foreign
Currency and Operations Risk" under "Item 3. Quantitative and Qualitative
Disclosures About Market Risk" located elsewhere in this Form 10-Q.
Income Taxes
The Company incurred a current provision for income taxes of approximately
$2.8 million for the first nine months of 1999 and realized a current benefit of
approximately $0.6 million for the same period of 1998. 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.
As of December 31, 1998, the Company had estimated net operating loss ("NOL")
carryforwards of $44.9 million for Argentina income tax reporting purposes which
can be used to offset future taxable income in Argentina. The carryforward
amount includes certain Argentina NOL carryforwards which were acquired and are
recorded at cost ($1.0 million), which is less than the calculated value for the
tax effect of these carryforwards ($6.0 million) under the provisions of
Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes. These unrecorded NOL carryforwards ($14.4 million) will reduce the
Company's foreign income tax provision for financial purposes by approximately
$5.0 million when their benefits are realized.
As a result of the significant decline in oil prices in 1998, primarily in the
fourth quarter, the Company believed that $16.2 million of Argentina NOL
carryforwards would expire in 1999 unutilized and therefore recorded a valuation
allowance against its Argentina deferred tax asset of approximately $5.7 million
in the fourth quarter of 1998 related to these carryforwards.
With the recovery of oil prices in the second and third quarters of 1999, it
is expected that the Company will utilize all of its Argentine NOL's including
those expiring in 1999 and those acquired but not previously recorded. As a
result, the Company has reduced its income tax provision for the nine months
ended September 30, 1999, by approximately $6.1 million and expects to reduce
its fourth quarter provision by the remaining $4.6 million relating to the
previously unrecorded acquired NOL's.
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<PAGE>
The Company has a U.S. Federal alternative minimum tax ("AMT") credit
carryforward of approximately $4.8 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. As a result of the historically low oil prices of 1998, the Company
incurred a NOL of $104.4 million for U.S. Federal income tax purposes in 1998
and will be able to carry back $30.8 million of the NOL two years to receive a
refund of prior income taxes paid and the remaining $73.6 million of the NOL
forward up to 20 years to offset future income taxes to be paid.
Year 2000 Compliance
Readers are cautioned that the forward-looking statements contained in the
following Year 2000 discussion should be read in conjunction with the Company's
disclosures under the heading "Forward-Looking Statements." The disclosures also
constitute a "Year 2000 Readiness Disclosure" and "Year 2000 Statement" within
the meaning of the Year 2000 Information and Readiness Disclosure Act of 1998.
The Year 2000 Information and Readiness Disclosure Act of 1998 does not insulate
the Company from liability under the federal securities laws with respect to
disclosures relating to Year 2000 information.
Statement of Readiness. The Company has undertaken various initiatives to
ensure that its hardware, software and equipment will function properly with
respect to dates before and after January 1, 2000. For this purpose, the phrase
"hardware, software and equipment" includes systems that are commonly thought of
as Information Technology systems ("IT"), as well as those Non-Information
Technology systems ("Non-IT") and equipment which include embedded technology.
IT systems include computer hardware and software and other related systems.
Non-IT systems include certain oil and gas production and field equipment,
gathering systems, office equipment, telephone systems, security systems and
other miscellaneous systems. The Non-IT systems present the greatest compliance
challenge since identification of embedded technology is difficult and because
the Company is, to a great extent, reliant on third parties for Non-IT
compliance.
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<PAGE>
The Company has formed a Year 2000 ("Y2K") Project team, which is chaired by
its Manager of Information Services. The team includes corporate staff and
representatives from the Company's business units. The phases of identification,
assessment, remediation and testing make up the Y2K directive.
The following is the Company's targeted Non-IT and IT compliance time line:
Status
-----------
DOMESTIC SERVICES
Non-IT Systems and Equipment:
Identification Phase....... Completed
Compliance................. Completed
IT Systems and Equipment:
Identification Phase....... Completed
Compliance................. Completed
INTERNATIONAL SERVICES
Non-IT Systems and Equipment:
Identification Phase....... Completed
Compliance................. Completed
IT Systems and Equipment:
Identification Phase....... Completed
Compliance................. Completed
The identification phase reported minimal non-compliance within the domestic
Non-IT technology and devices. Of the 1,800 components inventoried, only 157
devices were non-compliant. The Company has completed all strategy, planning,
equipment upgrades or replacement, renovation and testing, for domestic
operations. Of the 179 components inventoried in its international operations,
54 devices were categorized as non-compliant. The Company has completed all
strategy, planning, equipment upgrades or replacement, renovation and testing,
for its international operations including any items associated with our July
1999 El Huemul acquisition. As part of the Company's domestic and international
operational contingency planning, year-end roll-over and critical systems
monitoring have been implemented.
The Company has inventoried its IT equipment and systems and has completed all
corrective action. Critical domestic accounting equipment and software were
replaced or upgraded in mid-1998. The international accounting systems,
including those related to our November 1998 acquisition in Ecuador, are now
replaced or upgraded.
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<PAGE>
Included in the Company's Y2K Project are procedures to determine the
readiness of its business partners, such as service companies, technology
providers, transportation and communication providers, pipeline systems,
materials suppliers and oil and gas product purchasers. By use of
questionnaires, 14,000 notices were distributed which will allow the Company to
determine the extent to which these business partners are addressing their Y2K
issues. Each returned document is examined for a response that may be
detrimental to the Company's operations. To date, approximately 6,000 of the
Company's business partners have responded and those business partners who did
not respond and who are considered key businesses in the support of the
Company's operations were sent a second request, followed by direct
correspondence, to determine their readiness. Any material adverse responses
have been reviewed to determine an alternate business partner selection or the
need for alternative actions to mitigate the impact on the Company.
The Cost to Address Y2K Issues. The Company believes that the cost of the Y2K
Project will not exceed $2.5 million, excluding costs of Company employees
working on the Y2K Project. Costs incurred for the purchase of new software and
hardware are being capitalized and all other costs are being expensed as
incurred. To date, the Company has incurred Y2K Project costs of approximately
$2.2 million. The expenditures relate primarily to the use of contract service
consultants and the upgrading and replacement of existing software and hardware.
Y2K Worst-Case Scenario. The Company's initial results from its assessment
phase of the Y2K Project is that its internal systems have fewer Y2K compliance
problems than initially anticipated. As the Company has tested and does have
compliant all internal systems within its control, it believes its likely worst-
case scenario is the possibility of operational interruptions due to non-
compliance by third parties. This non-compliance could cause operational
problems such as temporary disruptions of certain production, delays in
marketing and transportation of production and delays of payments for oil and
gas sales. This risk should be minimized by the Company's efforts to communicate
and evaluate third party compliance.
The Company has developed contingency plans in the event that problems should
arise due to third party non-compliance or any failures of the Company's
systems. These plans are essentially complete and include, but are not limited
to, backup and recovery procedures, installations of new systems, replacement of
current services with temporary manual processes, finding non-technological
alternatives or sources of information, and finding alternative suppliers,
service companies and purchasers. Due to the uncertainties of Y2K, there is no
assurance that any contingency plan will cover all scenarios, therefore the
Company will continue to refine and test these contingency plans through January
1, 2000.
The Risks of Y2K Issues. The Company presently believes that the Y2K issue
will not pose significant operational problems. However, if all significant Y2K
issues are not properly identified, or assessment, remediation and testing are
not effected timely, the Y2K issues may materially and adversely impact the
Company's results of operations, liquidity and financial condition or materially
and adversely affect its relationships with its business partners. Additionally,
the lack of Y2K compliance by other entities may have a material and adverse
impact on the Company's operations or financial condition.
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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.
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<PAGE>
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.
The Company has various natural gas basis swaps in place for the last three
months of 1999 covering a total of 82,000 MMBtu of gas per day plus an
additional 3,000 MMBtu per day for the month of October 1999 for a total
weighted average differential of approximately one and one-half cents below
NYMEX. These natural gas basis swaps were used to reduce the Company's exposure
to increases in the basis differential between the NYMEX reference price and the
Company's industry delivery point indexes under which the gas is sold. During
the first ten months of 1999, the actual basis differential for this same volume
of gas was approximately two cents above NYMEX.
-27-
<PAGE>
Interest Rate Risk
The Company's interest rate risk exposure results primarily from short-term
rates, mainly LIBOR based borrowings from its commercial banks. To reduce the
impact of fluctuations in interest rates the Company maintains a portion of its
total debt portfolio in fixed rate debt. At September 30, 1999, the amount of
the Company's fixed rate debt was approximately 61 percent of total 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. The
following table provides information about the Company's long-term debt cash
flows and weighted average interest rates by expected maturity dates:
<TABLE>
<CAPTION>
Fair Value
There- at
1999 2000 2001 2002 2003 after Total 9/30/99
------- ------- -------- -------- ------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Long-Term Debt:
Fixed rate (in thousands)..... - - - - - $399,090 $399,090 $393,500
Average interest rate......... - - - - - 9.2% 9.2% -
Variable rate (in thousands).. - - $31,638 $126,5500 $94,912 - $253,100 $253,100
Average interest rate......... - - (a) (a) (a) - (a) -
</TABLE>
(a) LIBOR plus an increment, based on the level of outstanding senior debt to
the borrowing base, up to a maximum increment of 2.0 percent. The increment
above LIBOR at September 30, 1999, was 1.45 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, Bolivia, Ecuador and Yemen. For the first
nine months of 1999, the Company's operations in Argentina accounted for
approximately 29 percent of the Company's revenues, 54 percent of its operating
profit and 34 percent of its total assets. For the first nine months of 1998,
the Company's operations in Argentina accounted for approximately 20 percent of
the Company's revenues, 60 percent of its operating income and 26 percent of its
total assets. During such periods, the Company's operations in Argentina
represented its only foreign operations accounting for more than 10 percent of
its revenues, operating income or total assets. The Company expects that its
$122.0 million acquisition of the Argentina El Huemul concession in July 1999
will increase the revenues and operating profit percentages on a go-forward
basis. 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.
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 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 measure by the
Argentine Consumer Price Index declined from 200.7 percent as of June 1991 to a
negative 2.25 percent (-2.25%) as of September 1999.
-28-
<PAGE>
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, 1999, was
US$1:Bs 5.92. 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.
Prior to the Company's acquisition of Elf Ecuador in November 1998, its
previous operations in Ecuador were through a farm-in exploration joint venture
with two other companies in Block 19. Since 1992, the Government has generally
sought to reduce its participation in the economy and has implemented certain
macroeconomic reforms which were designed to reduce inflation. The Company
believes the current Government has a favorable attitude toward foreign
investment and has strong international relationships with the U.S.
The economy of Ecuador has been uneven in recent years and has recently
reached a crisis level, due in large part to recent low oil prices and damage
from El Nino floods. Because of the economic crisis, the country has
experienced shortfalls in its fiscal budget and massive reductions in its
monetary reserves. In April, Congress initiated audits of the banking system
and in July announced the decision to liquidate one bank, merge three others and
recapitalize four more with Ecuadorian state assistance. Year-to-date inflation
as of September 30, 1999, has reached 60 percent and the sucre (Ecuador's
monetary unit) has devalued by 102 percent. The exchange rate between sucres
and U.S. dollars at September 30, 1999, was 12,371:1 compared to the exchange
rate at January 1, 1999, of 6,391:1. All of the Company's revenues are U.S.
dollar based and since June 1, 1999, more than 70 percent of revenues are
collectible directly from international oil purchasers into U.S. bank accounts.
Although the Company believes that any currency risk associated with its
operations in Ecuador would not have a material impact on its financial position
or results of operations, it has policies in place to minimize its currency risk
in Ecuador. These policies include the maintenance of excess funds in U.S.
dollar accounts located in the U.S., the payment of operating expenses in local
currency and the conversion of local currency denominated receipts into U.S.
dollars.
-29-
<PAGE>
PART II
OTHER INFORMATION
-30-
<PAGE>
Item 1. Legal Proceedings
-----------------
For information regarding legal proceedings, see the Company's Form
10-K for the year ended December 31, 1998.
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
-----------------
A copy of the Company's press release dated November 3, 1999, is
attached as an exhibit hereto and incorporated herein by reference.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
a) Exhibits
The following documents are included as exhibits to this Form
10-Q. Those exhibits below incorporated by reference herein are
indicated as such by the information supplied in the parenthetical
thereafter. If no parenthetical appears after an exhibit, such
exhibit is filed herewith.
27. Financial data schedule.
99. Press release dated November 3, 1999, issued by the
Company.
b) Reports on Form 8-K
Form 8-K dated September 7, 1999, was filed September 8, 1999, to
report under Item 5 the Company's press release dated September 7,
1999, regarding strategic goals for 2000.
************************************************************************
-31-
<PAGE>
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 3, 1999 \s\ Michael F. Meimerstorf
------------------ -------------------------------------
Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)
-32-
<PAGE>
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
- ------ ----------------------------------------------------------------
27. Financial Data Schedule.
99. Press release dated November 3, 1999, issued by the Company.
-33-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM SEPTEMBER
30, 1999 FORM 10-Q AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 5,935
<SECURITIES> 0
<RECEIVABLES> 81,169
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 110,382
<PP&E> 1,537,550
<DEPRECIATION> 563,732
<TOTAL-ASSETS> 1,125,075
<CURRENT-LIABILITIES> 100,666
<BONDS> 652,190
0
0
<COMMON> 312
<OTHER-SE> 371,431
<TOTAL-LIABILITY-AND-EQUITY> 1,125,075
<SALES> 284,991
<TOTAL-REVENUES> 294,994
<CGS> 131,541
<TOTAL-COSTS> 131,541
<OTHER-EXPENSES> 107,722
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 44,321
<INCOME-PRETAX> 11,410
<INCOME-TAX> (2,930)
<INCOME-CONTINUING> 14,340
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 14,340
<EPS-BASIC> .25
<EPS-DILUTED> .25
</TABLE>
<PAGE>
EXHIBIT 99
For Further Information Contact
Robert E. Phaneuf
For Immediate Release Vice President - Corporate Development
Wednesday, November 3, 1999 (918) 592-0101
VINTAGE PETROLEUM, INC. REPORTS RECORD RESULTS
FOR THIRD QUARTER
Tulsa, Oklahoma - Vintage Petroleum, Inc. today announced dramatically
improved third quarter 1999 income of $27.3 million, or $0.43 a share, including
a $2.0 million after-tax gain from the sale of certain non-strategic oil and gas
properties. The record high results posted in the third quarter compare to a
loss of $9.9 million, or $0.19 per share, in the same quarter last year. A
substantially higher average oil price coupled with an increase in the price of
gas, significant gains in oil and gas production and lower exploration costs
accounted for the return to profitability.
Oil and gas production for the quarter grew 15 percent to a record 7.0
million equivalent barrels (BOE) from 6.0 million BOE in last year's period.
The increase is attributable to the acquisitions made in the fourth quarter of
last year and the purchase of the El Huemul concession in Argentina in July of
this year. As a result, oil production for the quarter increased 14 percent to
a record 4.6 million barrels. Company production of natural gas increased 19
percent to a record 13.9 billion cubic feet (Bcf) compared to 11.8 Bcf in last
year's quarter.
Aiding the increase in production was a substantially higher average price
of oil resulting from reduced supplies on the market attributable to the strong
adherence by OPEC to its accord reached earlier in the year. The company's
average realized price of oil rose 71 percent over the same quarter last year to
$18.50 per barrel. The average realized price of gas increased 14
-More-
<PAGE>
percent to $2.00 per Mcf compared to $1.76 per Mcf in the same quarter last
year.
Oil and gas sales rose 75 percent to a record $113.6 million principally
due to the impact of the higher average price of oil coupled with record oil and
gas production levels. Total revenues for the third quarter rose 72 percent to
$136.4 million, including a pre-tax gain from oil and gas property sales of $3.3
million.
Lease operating costs per BOE declined nearly 6 percent to $4.58 per BOE
compared to $4.88 per BOE in last year's third quarter. The decline results
primarily from the higher level of production and continued emphasis on cost
reduction measures initiated late last year. General and administrative
expenses also declined on a BOE basis, falling to $1.21 per BOE compared to
$1.30 per BOE in last year's third quarter. Exploration expense for the quarter
was $1.3 million composed of expenditures for seismic and other geological and
geophysical activities of $600,000 with the remaining $700,000 attributable to
leasehold impairments and unsuccessful exploratory drilling. In last year's
third quarter, exploration expense totaled $6.6 million consisting of $3.2
million of geological and geophysical activities and $3.4 million attributable
to leasehold impairments and dry hole costs. Interest expense rose 32 percent
to $15.2 million as a result of higher outstanding borrowings utilized to fund a
portion of capital spending, including acquisitions, in 1998.
For the quarter just ended, income before taxes was $36.4 million including
the impact of the $3.3 million pre-tax gain from non-strategic property sales
compared to a pre-tax loss of $16.3 million in last year's quarter. Net income
for the third quarter of 1999 was $27.3 million or $0.43 per share. Excluding
the after-tax gain from the sale of certain non-strategic oil and gas
properties, net income for the third quarter would be $25.3 million or $0.39 per
share. This compares to the third quarter of 1998 net loss of $9.9 million or
$0.19 per share. There were
-More-
<PAGE>
64.1 million weighted average shares outstanding in the third quarter of 1999
compared to the 51.7 million outstanding in the same period a year ago. The 24
percent increase in outstanding shares is due primarily to the impact of shares
issued to acquire certain oil and gas properties in November 1998, the June 1999
equity offering and the dilutive effects of stock options and contingent shares
which may become issuable under the $20 stock price guarantee delivered in
connection with the November 1998 acquisition.
Cash flow from operations (before working capital changes) for the third
quarter increased to a record $57.9 million compared to $17.2 million in the
year-ago quarter.
Nine Months 1999 Summary
For the nine months, oil and gas sales rose to $240.9 million, 17 percent
above the $206.6 million in the nine months of 1998. The higher sales were
primarily the result of an improvement in the realized price of oil. Total
revenues increased by 16 percent to $295.0 million, compared to $254.2 million
for the same period last year.
The net income in the first nine months of 1999 was $14.3 million, or $0.25
per share, compared to the 1998 period's loss of $21.0 million, or $0.41 a
share. There were 57.9 million weighted average shares outstanding in the first
nine months of 1999 compared to 51.7 million in the year-ago period. The factors
attributable to this 12 percent increase in outstanding shares are the same
factors which were responsible for the increase in outstanding shares in the
third quarter 1999 compared to the third quarter 1998.
Cash flow from operations (before changes in working capital) for the nine
months of 1999 was $93.7 million, 45 percent above the $64.8 million in the
year-ago period.
-More-
<PAGE>
Operational Update
Production
The State Tract 65-2 exploratory well in Galveston Bay was recently
successfully completed and is flowing to sales at a net daily rate of 7.0 MMcf
of gas and 75 barrels of oil. Coincident with the improved price of oil and the
acquisition of the El Huemul property in Argentina early in the third quarter,
the company resumed its Argentina drilling program in August. A mix of drilling
and workover exploitation activity is planned on both the El Huemul concession
as well as the company's previously existing San Jorge basin properties in the
fourth quarter and next year.
Bolivia and Brazil reached a significant milestone with the completion and
opening of the BTB pipeline early in the third quarter. Nevertheless, the
timing of the start-up of planned new power plants and other sources of
increasing gas demand in the Brazilian market from the current gross daily level
of approximately 100 MMcf to the BTB pipeline capacity of over 1 Bcf during the
next several years is uncertain. Delayed initial end-market demand from Brazil
and the termination of gas sales to Argentina resulted in the company's daily
Bolivian gas production during the third quarter averaging 19.8 MMcf, slightly
less than anticipated. For the fourth quarter, production appears likely to
average about 10 MMcf based on the current outlook for pipeline demand. If the
Brazilian demand build-up continues to be slower than anticipated during next
year, realized volumes could be less than Vintage's contracted average daily
volume of 32.1 MMcf but are expected to remain within the range bounded by its
contracted volume and an average daily volume of 19.3 MMcf supported by the
take-or-pay provision of the BTB gas contract. In addition to the BTB, Vintage
is actively pursuing other markets, such as new power projects and existing
domestic gas contracts approaching renewal, for the reserves not currently
-More-
<PAGE>
contracted to Brazil. The company estimates that, by year-end 1999, its net
Bolivian gas production capacity will reach 70 MMcf per day.
In Ecuador, workovers, facility upgrades and other exploitation activities
are underway aimed at increasing net daily oil production by year-end to over
1,900 barrels from the third quarter level of 1,496 barrels. The project is
designed to coincide with additional pipeline capacity expected to occur with
the completion, by year-end 1999, of expansion work on the existing
Transecuadorian Pipeline.
Exploration
Exploration in Bolivia during the third quarter continued the active pace
of the first half of the year with the drilling of the NJL X-103 and NJL X-102
wells. Testing is underway of the Upper Devonian Los Monos and Iquiri
formations. During the fourth quarter, the company expects to spud another well
in a new fault block to the west, the NJL X-110, targeting the Los Monos and
Iquiri formations. In the first quarter of 2000, the company plans to initiate
a well to test the deeper, potentially significant, Middle Devonian Huamampampa
formation.
In Yemen, the staging of equipment is underway in preparation for spudding
the first of three consecutive wells in December of this year. The first well
scheduled for drilling will test the An-Naeem prospect, located in the Northwest
portion of the S-1 Damis block immediately adjacent to the Janna Hunt Halewah
field.
In the Cedar Point project just onshore of the company's Galveston Bay
production, the USX Hematite #1 is completing. The Limonite, a 10,900-foot
Lower Vicksburg well in the same vicinity, is planned for the fourth quarter.
Additional leads and prospects have been identified for potential drilling next
year in both this area and Galveston Bay.
-More-
<PAGE>
Targets for 2000
Based on results to date, the revised 1999 non-acquisition capital budget
of $83 million, a preliminary non-acquisition budget of $128 million for the
year 2000, the company maintains its target to increase production from its
existing reserve base by 17 percent next year to 29 million BOE. Based on such
production targets and assumed NYMEX average reference prices for oil and gas of
$20 per barrel and $2.50 per Mcf, respectively, Vintage expects to generate cash
flow of approximately $185 million, or $2.85 per share.
Forward-Looking Statements
This release 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 release, other than statements of
historical facts, that address targets or estimates of proved oil and gas
reserves, future production, exploration drilling, exploitation activities and
events or developments that the company expects are forward-looking statements.
Although Vintage believes the expectations expressed in such forward-looking
statements are based on reasonable assumptions, 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, and general economic, market or
business conditions.
Vintage Petroleum is an independent energy company engaged in the
acquisition, exploitation, exploration and development of oil and gas properties
and the marketing of natural gas and crude oil. Company headquarters are in
Tulsa, Oklahoma and its common shares are traded on the New York Stock Exchange
under the symbol VPI.
-Table Follows-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
---------------------------------
(In thousands, except per share amounts)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------- ---------------------------------
1999 1998 1999 1998
------------- -------------- ---------------- ------------
REVENUES:
<S> <C> <C> <C> <C>
Oil and gas sales $113,580 $ 64,915 $240,902 $206,584
Gas marketing 16,404 12,593 38,905 39,664
Oil and gas gathering 1,734 1,476 5,184 6,811
Other income 4,711 301 10,003 1,152
------------- -------------- ---------------- ------------
136,429 79,285 294,994 254,211
------------- -------------- ---------------- ------------
COSTS AND EXPENSES:
Lease operating, including production taxes 31,886 29,487 80,991 91,693
Exploration costs 1,322 6,569 9,523 18,939
Gas marketing 15,705 12,061 37,095 37,701
Oil and gas gathering 1,311 1,334 3,932 5,851
General and administrative 8,413 7,825 24,482 23,922
Depreciation, depletion and amortization 26,231 26,797 83,240 80,283
Interest 15,185 11,525 44,321 30,795
------------- -------------- ---------------- ------------
100,053 95,598 283,584 289,184
------------- -------------- ---------------- ------------
Income (loss) before income taxes 36,376 (16,313) 11,410 (34,973)
PROVISION (BENEFIT) FOR INCOME TAXES:
Current 2,749 (125) 2,796 (586)
Deferred 6,349 (6,263) (5,726) (13,372)
------------- -------------- ---------------- ------------
NET INCOME (LOSS) $ 27,278 $ (9,925) $ 14,340 $(21,015)
============= ============== ================ ============
EARNINGS (LOSS) PER SHARE:
Basic $.44 $(.19) $.25 $(.41)
============= ============== ================ ============
Diluted $.43 $(.19) $.25 $(.41)
============= ============== ================ ============
Weighted average common shares outstanding:
Basic 62,309 51,733 56,505 51,664
============= ============== ================ ============
Diluted 64,143 51,733 57,869 51,664
============= ============== ================ ============
</TABLE>
-Table Follows-
<PAGE>
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
SUMMARY BALANCE SHEET DATA
--------------------------
(In thousands)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
--------------- -----------------
<S> <C> <C>
Total current assets $ 110,382 $ 84,142
Property, plant and equipment, net 973,818 898,242
Total assets 1,125,075 1,014,175
Total current liabilities 100,666 66,925
Long-term debt 652,190 672,507
Stockholders' equity 371,743 273,958
</TABLE>
<TABLE>
<CAPTION>
SUMMARY OPERATING DATA
----------------------
(Unaudited)
----------
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
1999 1998 1999 1998
----------- ------------- ------------ ------------
<S> <C> <C> <C> <C>
Production:
Oil (MBbls) -
U.S. 2,183 2,500 6,484 7,509
Argentina 2,287 1,552 5,330 4,637
Ecuador 138 - 381 -
Bolivia 28 30 58 99
Total 4,636 4,082 12,253 12,245
Gas (MMcf) -
U.S. 9,577 10,386 29,010 31,530
Argentina 2,547 - 2,921 -
Bolivia 1,817 1,372 3,345 4,036
Total 13,941 11,758 35,276 35,566
Total MBOE 6,959 6,042 18,132 18,172
Average price:
Oil (per Bbl) -
U.S. $ 17.50 (a) $ 11.08 $ 14.01 (a) $ 11.64
Argentina 19.72 10.43 15.32 11.18
Ecuador 14.28 - 10.74 -
Bolivia 16.95 10.24 14.53 11.49
Total 18.50 (a) 10.83 14.48 (a) 11.46
Gas (per Mcf) -
U.S. $ 2.41 $ 1.90 $ 1.98 $ 2.00
Bolivia .70 .73 .63 .81
Argentina 1.37 - 1.32 -
Total 2.00 1.76 1.80 1.86
</TABLE>
(a) Includes the cost of hedging activities.
-30-
