UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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
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VINTAGE PETROLEUM, INC.
-----------------------
(Exact name of registrant as specified in charter)
Delaware 73-1182669
-------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
4200 One Williams Center Tulsa, Oklahoma 74172
- -----------------------------------------------------------------------------
(Address of principal (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 July 31, 1999
----- ----------------------------
Common Stock, $.005 Par Value 62,347,866
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PART I
FINANCIAL INFORMATION
-2-
ITEM 1. FINANCIAL STATEMENTS
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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED BALANCE SHEETS
---------------------------
(In thousands, except shares
and per share amounts)
(Unaudited)
ASSETS
------
June 30, December 31,
1999 1998
------------- ------------
CURRENT ASSETS:
Cash and cash equivalents $ 83,436 $ 5,245
Accounts receivable -
Oil and gas sales 51,077 54,680
Joint operations 3,258 5,905
Prepaids and other current assets 23,674 18,312
------------- ------------
Total current assets 161,445 84,142
------------- ------------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Oil and gas properties, successful efforts method 1,388,892 1,368,914
Oil and gas gathering systems 15,363 14,774
Other 16,616 16,276
------------- ------------
1,420,871 1,399,964
Less accumulated depreciation, depletion and amortization 556,042 501,722
------------- ------------
864,829 898,242
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DEFERRED INCOME TAXES 14,022 2,505
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OTHER ASSETS, net 32,518 29,286
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TOTAL ASSETS $ 1,072,814 $ 1,014,175
============= ============
See notes to unaudited consolidated financial statements.
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VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
June 30, December 31,
1999 1998
------------- ------------
CURRENT LIABILITIES:
Revenue payable $ 16,609 $ 17,382
Accounts payable - trade 15,504 24,812
Other payables and accrued liabilities 24,351 24,731
------------- ------------
Total current liabilities 56,464 66,925
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LONG-TERM DEBT 673,662 672,507
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OTHER LONG-TERM LIABILITIES 443 785
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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,
62,107,066 and 53,107,066 shares issued and
outstanding, respectively 311 266
Capital in excess of par value 311,916 230,736
Retained earnings 30,018 42,956
------------- ------------
342,245 273,958
------------- ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 1,072,814 $ 1,014,175
============= ============
See notes to unaudited consolidated financial statements.
-4-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED STATEMENTS OF INCOME
---------------------------------
(In thousands, except per share amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- --------------------
1999 1998 1999 1998
---------- ---------- --------- ---------
REVENUES:
Oil and gas sales $73,828 $ 69,022 $127,322 $141,669
Gas marketing 12,183 12,816 22,501 27,071
Oil and gas gathering 1,870 2,656 3,450 5,335
Other income 4,680 438 5,292 851
---------- --------- --------- ----------
92,561 84,932 158,565 174,926
---------- --------- --------- ----------
COSTS AND EXPENSES:
Lease operating, including production taxes 25,258 30,026 49,105 62,205
Exploration costs 2,314 10,371 8,201 12,369
Gas marketing 11,596 12,040 21,390 25,640
Oil and gas gathering 1,427 2,265 2,621 4,518
General and administrative 8,136 9,014 16,069 16,098
Depreciation, depletion and amortization 24,804 26,619 57,009 53,486
Interest 14,576 9,978 29,136 19,270
---------- --------- --------- ----------
88,111 100,313 183,531 193,586
---------- --------- --------- ----------
Income (loss) before income taxes 4,450 (15,381) (24,966) (18,660)
PROVISION (BENEFIT) FOR INCOME TAXES:
Current 19 (19) 47 (461)
Deferred (752) (5,854) (12,075) (7,109)
---------- --------- --------- ----------
NET INCOME (LOSS) $ 5,183 $ (9,508) $(12,938) $(11,090)
========== ========= ========= ==========
EARNINGS (LOSS) PER SHARE:
Basic $.10 $(.18) $(.24) $(.21)
========== ========= ========= ==========
Diluted $.09 $(.18) $(.24) $(.21)
========== ========= ========= ==========
Weighted average common shares outstanding:
Basic 53,997 51,649 53,555 51,629
========== ========= ========= ==========
Diluted 55,857 51,649 53,555 51,629
========== ========= ========= ==========
See notes to unaudited consolidated financial statements.
-5-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
---------------------------------------------------------
FOR THE SIX MONTHS ENDED JUNE 30, 1999
--------------------------------------
(In thousands)
(Unaudited)
Capital
Common Stock In Excess
---------------- of Par Retained
Shares Amount Value Earnings Total
------------------------------------- ------------
Balance at December 31, 1998 53,107 $ 266 $ 230,736 $ 42,956 $ 273,958
Net loss - - - (12,938) (12,938)
Issuance of common stock 9,000 45 81,180 - 81,225
-------- ------ --------- -------- ------------
Balance at June 30, 1999 62,107 $ 311 $ 311,916 $ 30,018 $ 342,245
======== ====== ========= ======== ============
See notes to unaudited consolidated financial statements.
-6-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
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CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(In thousands)
(Unaudited)
Six Months Ended
June 30,
-----------------------
1999 1998
----------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss $ (12,938) $ (11,090)
Adjustments to reconcile net loss to
cash provided by operating activities -
Depreciation, depletion and amortization 57,009 53,486
Exploration costs 8,201 12,369
Benefit for deferred income taxes (12,075) (7,109)
Gain on property sales (4,366) -
----------- ----------
35,831 47,656
Decrease in receivables 6,250 7,309
Decrease in payables and accrued liabilities (7,604) (4,864)
Other (376) 136
----------- ----------
Cash provided by operating activities 34,101 50,237
----------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property, plant and equipment -
Oil and gas properties (31,197) (110,539)
Other property and equipment (930) (3,233)
Proceeds from sales of oil and gas properties 4,765 -
Other (4,574) (8,926)
----------- ----------
Cash used by investing activities (31,936) (122,698)
----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock 81,225 364
Sale of 9 3/4% Senior Subordinated Notes 146,000 -
Advances on revolving credit facility and other borrowings 11,526 83,141
Payments on revolving credit facility and other borrowings (161,397) (10,722)
Dividends paid (1,328) (3,097)
----------- ----------
Cash provided by financing activities 76,026 69,686
----------- ----------
Net increase (decrease) in cash and cash equivalents 78,191 (2,775)
Cash and cash equivalents, beginning of period 5,245 5,797
----------- ----------
Cash and cash equivalents, end of period $ 83,436 $ 3,022
=========== ==========
See notes to unaudited consolidated financial statements.
-7-
VINTAGE PETROLEUM, INC. AND SUBSIDIARIES
----------------------------------------
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
June 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 air 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-
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 six months of 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 $28,392,646 and $18,164,262 for the six
months ended June 30, 1999 and 1998, respectively. Cash payments for U.S.
Federal and state income taxes were $1,473,252 during the six months ended June
30, 1998. There were no cash payments made for U.S. income taxes in the first
six months of 1999. During the six months ended June 30, 1999 and 1998, the
Company made cash payments of $47,073 and $1,256,041, respectively, for foreign
taxes.
Earnings Per Share
The Company applies Financial Accounting Standards Board issued 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 six months ended June 30, 1999
and 1998, and for the three months ended June 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 the six months ended June 30, 1999 or 1998, or the three
months ended June 30, 1998, the Company's diluted weighted average outstanding
common shares as calculated under SFAS No. 128 would have been 55,077,315,
52,920,518 and 52,927,017, respectively. In addition, for the six months ended
June 30, 1999 and 1998, and for the three months ended June 30, 1999 and 1998,
the Company had outstanding stock options for 3,035,322, 1,665,000, 819,000 and
819,000 additional shares of the Company's common stock, respectively, with
average exercise prices of $14.03, $17.69, $20.11 and $20.11, respectively,
which were antidilutive.
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.
-9-
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 six month periods
ended June 30, 1999 and 1998, the Company had no non-owner changes in equity
other than net losses.
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 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.
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.
-10-
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. ("Total") and a
subsidiary of Repsol S.A. ("Repsol") in early July 1999 as discussed in Note 6
below. At June 30, 1999, the majority of the $81.2 million was included in cash
and cash equivalents pending the closing of these acquisitions. 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 $2.2 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.
-11-
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 six months and second quarters of 1999 and 1998 is shown in the following
table:
Exploration and Production
-------------------------------
Other Gas
U.S. Argentina Foreign Gathering Marketing Corporate Total
---------- --------- -------- ---------- ---------- --------- -----------
Six months ended 6/30/99
- ------------------------
Revenues from external customers $ 92,249 $ 36,892 $ 3,312 $3,450 $22,501 $ 161 $ 158,565
Intersegment revenues - - - 650 574 - 1,224
Depreciation, depletion and
amortization expense 40,874 12,881 1,338 694 - 1,222 57,009
Operating income (loss) 10,475 13,252 (3,785) 135 1,111 (949) 20,239
Total assets 536,725 244,812 116,818 7,064 8,947 158,448 1,072,814
Capital investments 9,162 1,061 20,980 589 - 335 32,127
Long-lived assets 505,703 235,730 115,547 4,245 - 3,604 864,829
Six months ended 6/30/98
- ------------------------
Revenues from external customers $103,204 $ 35,656 $ 3,122 $5,335 $27,071 $ 538 $ 174,926
Intersegment revenues - - - 451 767 - 1,218
Depreciation, depletion and
amortization expense 37,367 12,785 1,536 871 - 927 53,486
Operating income (loss) 8,431 8,645 (1,355) (54) 1,431 (390) 16,708
Total assets 580,323 250,066 59,413 7,865 11,636 46,826 956,129
Capital investments 66,485 27,841 16,213 859 - 2,374 113,772
Long-lived assets 546,567 242,739 55,281 4,201 - 5,980 854,768
Three months ended 6/30/99
- --------------------------
Revenues from external customers $ 54,149 $ 22,235 $ 2,127 $1,870 $12,184 $ (4) $ 92,561
Intersegment revenues - - - 344 258 - 602
Depreciation, depletion and
amortization expense 17,137 5,923 678 419 - 647 24,804
Operating income (loss) 16,184 10,602 328 24 587 (563) 27,162
Capital investments 3,994 522 8,039 (48) - 107 12,614
Three months ended 6/30/98
- --------------------------
Revenues from external customers $ 50,601 $ 16,923 $ 1,638 $2,656 $12,816 $ 298 $ 84,932
Intersegment revenues - - - 216 464 - 680
Depreciation, depletion and
amortization expense 18,578 6,470 733 313 - 525 26,619
Operating income (loss) 1,613 2,803 (1,430) 77 777 (228) 3,612
Capital investments 38,143 14,831 10,637 (54) - 1,232 64,789
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-
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 six months of 1999 and the calendar years of 2000
through 2004 are $0.7 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.
6. SUBSEQUENT EVENTS
During July 1999, the Company purchased from Total and Repsol 100 percent of
the El Huemul concession located in the San Jorge basin in Argentina for $121.9
million in cash. Of the total purchase price, $103.0 million was paid at closing
utilizing the $81.2 million in net proceeds from the June 1999 common stock
offering and $21.8 million in advances under the Company's revolving credit
facility. The remaining $18.9 million is due on or before December 31, 1999.
Proved reserves for these properties as of July 1, 1999, as estimated by
Netherland, Sewell & Associates, Inc., using a NYMEX reference oil price of
$17.32 per Bbl and an average gas price of $1.02 per Mcf, were 44.7 MMBbls of
oil and 81.1 Bcf of gas, or 58.2 MMBOE, and had a present value of the estimated
future net revenues before income taxes (utilizing a 10 percent discount rate)
of $233.3 million. Aggregate net daily sales volumes from the El Huemul
concession at the time of acquisition were approximately 9,400 barrels of oil
and 19 million cubic feet of gas or a combined total of 12,565 barrels of oil
equivalent.
-13-
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
---------------------------------------------
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
------------------------------------------------
Results of Operations
The Company's results of operations have been significantly affected by its
success in acquiring oil and gas properties and its ability to maintain or
increase production through its exploitation and exploration activities.
Fluctuations in oil and gas prices have also significantly affected the
Company's results. The following table reflects the Company's oil and gas
production and its average oil and gas sales prices for the periods presented:
Three Months Six Months
Ended Ended
June 30, June 30,
------------------ -----------------
1999 1998 1999 1998
--------- ------- ------- --------
Production:
Oil (MBbls) -
U.S. (1)..... 2,196 2,535 4,301 5,009
Argentina.... 1,492 1,546 3,043 3,084
Ecuador...... 125 - 243 -
Bolivia...... 17 35 30 70
Total........ 3,830 4,116 7,617 8,163
Gas (MMcf) -
U.S. (1)..... 9,302 10,964 19,433 21,144
Bolivia (2).. 845 1,276 1,528 2,664
Argentina.... 304 - 374 -
Total........ 10,451 12,240 21,335 23,808
Total MBOE (1)... 5,571 6,156 11,173 12,131
Average prices:
Oil (per Bbl) -
U.S.......... $ 14.33 $ 10.96 $ 12.24 $ 11.91
Argentina.... 14.70 10.95 12.00 11.56
Ecuador...... 11.25 - 8.75 -
Bolivia...... 15.13 15.23 12.22 12.02
Total........ 14.37 10.99 12.03 11.78
Gas (per Mcf) -
U.S.......... $ 1.94 $ 2.07 $ 1.77 $ 2.04
Bolivia...... .56 .87 .54 .86
Argentina.... 1.00 - .99 -
Total........ 1.80 1.94 1.67 1.91
________
(1) First half 1998 production was reduced by approximately 159 MBbls of oil
and 486 MMcf of gas, or 240 MBOE, due to severe weather conditions in
California. Second quarter 1998 production was reduced by approximately 46
MBbls of oil and 236 MMcf of gas, or 85 MBOE, due to severe weather
conditions in California. During the three month and six month periods
ended June 30, 1999, the Company elected to shut-in approximately 184 MBbls
and 519 MBbls of oil production, respectively, due to historically low oil
prices.
(2) During the three month and six month periods ended June 30, 1999, the
Company's Bolivian gas production was significantly curtailed due to
decreased demand in the Argentina market for Bolivian gas.
-14-
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 two percent increase in its average oil
price in the first half of 1999 compared to the first half of 1998. The Company
realized an average oil price for the first half of 1999 which was approximately
94 percent of WTI posted prices compared to a realization of 92 percent of WTI
posted prices for the year earlier first half. The Company's average realized
oil price remained at 78 percent of the NYMEX reference price ("NYMEX") in the
first half of 1999 consistent with 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 overall average gas price for the first six months of 1999 was 13
percent lower than 1998's first six months and seven percent lower for the
second quarter of 1999 versus 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 six months of 1999
covering a total of 82,000 MMBtu of gas per day plus an additional 3,000 MMBtu
per day for the period of July through 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 half of
1999, the Company's overall and U.S. average gas prices were each reduced by
four cents as a result of these swaps. The Company's overall and U.S. average
gas prices for the second quarter of 1999 were each reduced by two cents as a
result of the swaps.
In the second quarter of 1999, the Company entered into contracts hedging
20,000 barrels of oil per day for the month of July 1999 at an average NYMEX
reference price of $18.07 per barrel. The Company's overall and U.S. average
oil prices for the first half of 1999 were increased by four cents and six
cents, respectively, as a result of oil hedges. The Company's overall and U.S.
average oil prices for the second quarter of 1999 were increased by seven cents
and 12 cents, respectively, as a result of oil hedges.
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 second 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 $2.4 million and $3.7 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 $0.6 million and $1.0 million, respectively, based on second
quarter 1999 gas production.
-15-
Period to Period Comparison
Three months ended June 30, 1999, Compared to three months ended June 30, 1998
The Company reported net income of $5.2 million for the quarter ended June
30, 1999, compared to a net loss of $9.5 million for the year-earlier quarter.
The increase in the Company's net income is primarily due to the 31 percent
increase in the average oil price received, the recognition of $4.4 million in
gains related to the sales of certain non-strategic oil and gas properties, a 16
percent decrease in lease operating expenses and an $8.1 million decrease in
exploration costs, all partially offset by a $4.6 million increase in interest
expense and a 10 percent decrease in production on an equivalent barrel basis.
Oil and gas sales increased $4.8 million (7 percent), to $73.8 million for
the second quarter of 1999 from $69.0 million for the second quarter of 1998. A
31 percent increase in average oil prices, partially offset by a seven percent
decrease in oil production, accounted for an increase in oil sales of $10.0
million. A seven percent decrease in average gas prices, coupled with a 15
percent decrease in gas production, accounted for a $5.2 million decrease in gas
sales for the 1999 second quarter as compared to the year earlier quarter. The
seven percent decrease in oil production is primarily the result of the impact
of shutting-in certain domestic properties for a portion of the period as a
result of the historically low oil prices and the impact of natural production
declines. The 17 percent decrease in gas production primarily related to the
natural production declines in the Company's Galveston Bay properties and the
curtailment of Bolivian production being delivered to Argentina.
Other income increased $4.3 million (1,075 percent), to $4.7 million for the
second quarter of 1999 from $0.4 million for the second quarter of 1998. The
increase is primarily the result of the recognition of gains of $4.4 million
resulting from the sales of certain non-strategic oil and gas properties during
the second quarter of 1999.
Lease operating expenses, including production taxes, decreased $4.7 million
(16 percent), to $25.3 million for the second quarter of 1999 from $30.0 million
for the second quarter 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 second quarter as a result of historically
low oil prices, the rebidding of operating services and supplies and the
restructuring of certain field operations. As a result of the Company's cost
reduction efforts, lease operating expenses per equivalent barrel produced
decreased seven percent to $4.53 in the second quarter of 1999 from $4.88 for
the same period in 1998.
Exploration costs decreased $8.1 million (78 percent), to $2.3 million for
the second quarter of 1999 from $10.4 million for same period of 1998. During
the second quarter of 1999, the Company's exploration costs included $1.0
million for lease impairments, $0.8 million for the acquisition of 3-D seismic
data primarily in Yemen and western Oklahoma, $0.5 million for unsuccessful
exploratory drilling and other geological and geophysical costs. The Company's
1998 second quarter exploration costs consisted primarily of $8.5 million in 3-D
seismic acquisition costs primarily in the U.S. Gulf Coast and Bolivia, $0.8
million for lease expirations and $1.0 million in unsuccessful exploratory
drilling and other geological and geophysical costs.
-16-
General and administrative expenses decreased $0.9 million (10 percent), to
$8.1 million for the second quarter of 1999 from $9.0 million for the second
quarter of 1998 as the result of the Company's cost cutting efforts in 1999,
more than offsetting 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 10 percent decrease in costs, general and administrative expenses per
equivalent barrel produced remained flat with the year-earlier quarter at $1.46
as a result of the 10 percent decrease in the Company's oil and gas production.
Depreciation, depletion and amortization decreased $1.8 million (7 percent),
to $24.8 million for the second quarter of 1999 from $26.6 million for the
second quarter of 1998, due primarily to the 10 percent decrease in the
Company's oil and gas production for the second quarter of 1999. The average
amortization rate per equivalent barrel of the Company's oil and gas properties
increased from $4.19 in the second quarter of 1998 to $4.26 in the second
quarter of 1999.
Interest expense increased $4.6 million (46 percent), to $14.6 million for
the second quarter of 1999 from $10.0 million for the second quarter of 1998,
due primarily to a 37 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 7.95% in the second quarter of 1999
as compared to 7.84% in the second quarter of 1998. The Company had $5.5 million
and $5.3 million of accrued interest payable at June 30, 1999, and December 31,
1998, respectively, included in other payables and accrued liabilities.
Six months ended June 30, 1999, Compared to six months ended June 30, 1998
The Company reported a net loss of $12.9 million for the six months ended
June 30, 1999, compared to a net loss of $11.1 million for the year-earlier
period. The increase in the Company's net loss is primarily due to the eight
percent decrease in production on an equivalent barrel basis, a 13 percent
decrease in average gas prices and an increase in the Company's overall average
DD&A rate as a result of reduced year-end 1998 reserves due to historically low
oil prices, and an increase in interest expense. These items were partially
offset by a 21 percent decrease in lease operating costs and the recognition of
$4.4 million in gains related to the sales of non-strategic oil and gas
properties.
Oil and gas sales decreased $14.4 million (10 percent), to $127.3 million
for the first six months of 1999 from $141.7 million for the six months of 1998.
A 13 percent decrease in average gas prices, coupled with a 10 percent decrease
in gas production, accounted for a $9.9 million decrease in oil and gas sales
for the first six months of 1999 as compared to the year-earlier period. A two
percent increase in average oil prices was offset by a seven percent decrease in
oil production and accounted for an additional decrease of $4.5 million. The
seven percent decrease in oil production is primarily as a result of shutting-in
certain domestic properties for a portion of the period as a result of the
historically low oil prices. The 10 percent decrease in gas production primarily
related to the natural production declines in the Company's Galveston Bay
properties and the curtailment of Bolivian production being delivered to
Argentina.
-17-
Other income increased $4.4 million (489 percent), to $5.3 million for the
first half of 1999 from $0.9 million for the first half of 1998. The increase
is primarily the result of the recognition of gains of $4.4 million resulting
from the sales of certain non-strategic oil and gas properties during the first
half of 1999.
Lease operating expenses, including production taxes, decreased $13.1
million (21 percent), to $49.1 million for the first six months of 1999 from
$62.2 million for the first six 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 as a result of historically low oil
prices, the rebidding of operating services and supplies and the restructuring
of certain field operations. The first half of 1998 included lease operating
costs of approximately $1.5 million relating to the storm damage clean up and
repairs required as a result of severe weather in California; 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 14
percent to $4.40 in the first six months of 1999 from $5.13 for the same period
in 1998.
Exploration costs decreased $4.2 million (34 percent), to $8.2 million for
the first six months of 1999 from $12.4 million for same period of 1998. During
the first six 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, $1.4 million for lease impairments, $1.6 million for unsuccessful
exploratory drilling and other geological and geophysical costs. The Company's
1998 first six months exploration costs consisted primarily of $10.5 million in
3-D seismic acquisition costs primarily in the U.S. Gulf Coast and Bolivia, $0.8
million in lease expirations and $1.1 million in unsuccessful exploratory
drilling and other geological and geophysical costs.
General and administrative expenses for the first six months of 1999 of
$16.1 million were flat with the first six months of 1998 as a result of the
Company's cost cutting efforts during 1999 completely offsetting 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. General and administrative expenses per
equivalent barrel produced increased to $1.44 from $1.33 in the year earlier
first half primarily as a result of the eight percent decrease in equivalent
barrel production.
Depreciation, depletion and amortization increased $3.5 million (7 percent),
to $57.0 million for the first half of 1999 from $53.5 million for the first
half of 1998, due primarily to the 16 percent increase in the average
amortization rate per equivalent barrel of the Company's oil and gas properties
from $4.26 in the first half of 1998 to $4.93 in 1999. This increase was
partially offset by the eight percent decrease in the Company's oil and gas
production for the first half of 1999 and is primarily as 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 $9.8 million (51 percent), to $29.1 million for
the first half of 1999 from $19.3 million for the first half of 1998, due
primarily to a 42 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 7.89% in the first half of 1999 from 7.84% in
the first half of 1998.
-18-
Capital Expenditures
During the first six months of 1999, the Company's domestic oil and gas
capital expenditures totaled $9.8 million. Exploratory activities accounted for
$4.9 million of these expenditures with exploitation activities contributing
another $3.8 million. The $1.1 million balance of the domestic capital
expenditures relates to post-closing adjustments on prior year acquisitions and
gathering system additions. During the first six months of 1999, the Company's
international oil and gas capital expenditures totaled $22.0 million, including
$15.0 million and $4.5 million in Bolivia and Yemen, respectively, primarily on
exploratory drilling in Bolivia and seismic activity in Yemen.
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 $11.7 million was spent during the first six months primarily on
exploratory drilling activities. Through June 1999, the Company had completed
approximately 6,528 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.
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 six months of 1999.
During June 1999, the Company entered into a definitive purchase and sale
agreement with a subsidiary of Total Fina S.A. ("Total") to purchase its 70
percent interest in certain oil and gas properties located in the San Jorge
basin in Argentina for $93 million, subject to closing adjustments. 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, in July 1999, the Company purchased the remaining 30 percent
interest in these oil and gas properties from a subsidiary of Repsol S.A.
("Repsol") for $28.9 million in cash, including a deferred payment of $5.9
million due on or before December 31, 1999. The $103 million in cash required
for 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.
-19-
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 58 percent to
exploration activities and 42 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.
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.
-20-
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 July 1999 (see "-Capital
Expenditures"). At June 30, 1999, the majority of the proceeds were invested in
a money market account and are reflected in the cash and cash equivalents line
on the Company's June 30, 1999, balance sheet. 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
$2.2 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.
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 July 31, 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 7.0
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 $76.9 million
at July 31, 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.
Currently, the borrowing base of $400 million has not been adjusted to reflect
the Company's July 1999 acquisitions from Total and Repsol or the impact of the
recent improvements in oil and gas prices.
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
second 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
-21-
liquidity.
Inflation
In recent years, U.S. inflation has not had a significant impact on the
Company's operations or financial condition.
Income Taxes
The Company incurred a current provision for income taxes of approximately
$47,000 for the first six months of 1999 and realized a current benefit of
approximately $7.1 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 ($17.3 million)
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 ("SFAS 109"). These unrecorded NOL carryforwards
($14.4 million) will reduce the Company's foreign income tax provision for
financial purposes in future years by approximately $5.0 million if their
benefit is 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. Product prices
have recovered substantially subsequent to the March OPEC meeting. Should prices
remain improved during the remainder of 1999, it could be possible for the
Company to utilize a portion of or all of the NOL's expiring in 1999 and thereby
require a reversal of the valuation allowance established in 1998. The impact of
this reversal would be to reduce the Company's deferred tax provision.
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. The Company incurred a tax NOL for U.S. purposes in 1998 and will be
able to carry back the NOL two years and/or forward 20 years to receive a refund
of prior income taxes paid or to offset future income taxes to be paid.
-22-
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.
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.
-23-
The following is the Company's targeted Non-IT and IT compliance time line:
Completion
Date
----------------
DOMESTIC SERVICES
Non-IT Systems and Equipment:
Identification Phase...... Completed
Compliance................ August 1999
IT Systems and Equipment:
Identification Phase...... Completed
Compliance................ September 1999
INTERNATIONAL SERVICES
Non-IT Systems and Equipment:
Identification Phase...... Completed
Compliance................ September 1999
IT Systems and Equipment:
Identification Phase...... Completed
Compliance................ September 1999
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. With the strategy and planning phase for domestic
equipment upgrades or replacement complete, the Company has begun renovation and
testing, with priority placed on plants and units housing the greater number of
non-compliant equipment. Of the 179 components inventoried in its international
operations, 54 devices were categorized as non-compliant. The strategy and
planning phase has begun to renovate and test the equipment.
The Company has inventoried its IT equipment and systems and is currently
undertaking the appropriate corrective action. Critical domestic accounting
equipment and software were replaced or upgraded in mid-1998. The international
accounting systems are in various stages of completion with all systems
scheduled to be compliant by September 1999.
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 5,600 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
will be reviewed to determine an alternate business partner selection or the
need for alternative actions to mitigate the impact on the Company.
-24-
The Cost to Address Y2K Issues. The Company believes that the cost of the
Y2K Project will not exceed $4.0 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
$1.5 million. The expenditures relate primarily to the upgrading and replacement
of existing software and hardware and the use of contract service consultants.
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 plans to have all internal
systems within its control compliant and tested before the year 2000, 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 is currently developing contingency plans in the event that
problems arise due to third party non-compliance or any failures of the
Company's systems. These plans should be completed by the third quarter of 1999
and will 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.
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.
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.
-25-
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.
-26-
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 six
months of 1999 covering a total of 82,000 MMBtu of gas per day plus an
additional 3,000 MMBtu per day for the period of July through October 1999 for a
total weighted average differential of approximately one cent 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
eight months of 1999, the actual basis differential for this same volume of gas
was approximately three and one-half cents above NYMEX.
The Company has contracts hedging 20,000 barrels of oil per day for July
1999 at an average NYMEX reference price of $18.07 per barrel. The NYMEX
reference price as of June 30, 1999, was $19.29 per barrel. Fair value
represents values for the same contracts using comparable market prices at June
30, 1999. At June 30, 1999, the fair value amount of the contracts was $1.3
million lower than the aggregate contract amount.
-27-
Interest Rate Risk
The Company's interest rate risk exposure results primarily from short-
term rates, mainly LIBOR based borrowings from its commercial banks. To
reduce the impact of fluctuations in interest rates the Company maintains a
portion of its total debt portfolio in fixed rate debt. At June 30, 1999,
the amount of the Company's fixed rate debt was approximately 59 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:
Fair Value
There- at
1999 2000 2001 2002 2003 after Total 6/30/99
------ ----- ------- --------- --------- --------- --------- ----------
Long-Term Debt:
Fixed rate (in thousands) - - - - - $399,062 $399,062 $ 400,188
Average interest rate - - - - - 9.2% 9.2% -
Variable rate (in thousands) - - $34,325 $137,300 $102,975 - $274,600 $ 274,600
Average interest rate - - (a) (a) (a) - (a) -
(a) LIBOR plus an increment, based on the level of outstanding senior debt
to the borrowing base, up to a maximum increment of 2.0 percent. The
increment above LIBOR at June 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 six months of 1999, the Company's operations in Argentina
accounted for approximately 23 percent of the Company's revenues, 65
percent of its operating profit and 23 percent of its total assets. For the
first six months of 1998, the Company's operations in Argentina accounted
for approximately 20 percent of the Company's revenues, 52 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's $121.9 million acquisition of the
Argentina El Huemul concession in July 1999 will increase each of the
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 5.14 percent (-5.14%) as of June
1999.
-28-
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 June 30, 1999, was US$1:Bs
5.81. 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. Due to the current economic crisis, the sucre (Ecuador's
monetary unit) has lost approximately 48 percent of its value so far this year
and inflation has reached nearly 55 percent. President Jamil Mahaud announced
March 11, 1999, the freezing of Ecuadorian bank accounts for one year. This
restriction in liquidity has resulted in the improvement in the exchange rate
between sucres and U.S. dollars from 12,675:1 on March 5, 1999, to 9,080:1 on
April 22, 1999. The exchange rate between sucres and U.S. dollars on June 30,
1999, was 11,667:1. Earlier this year the income tax was replaced by a one
percent tax on all financial transactions. The purpose of the reform is to
reduce tax evasion and increase tax collection by the Government, without
increasing the tax burden on taxpayers. On April 22, 1999, Congress reinstated
the income tax, but kept the one percent tax on transactions as a alternative
minimum tax for 1999. Although the Company believes 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 that
will reduce its exposure to currency risk in Ecuador. These policies include
the maintenance of all 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-
PART II
OTHER INFORMATION
-30-
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
---------------------------------------------------
The Annual Meeting of Stockholders of the Company (the "Annual
Meeting") was held on May 11, 1999, in Tulsa, Oklahoma. At the Annual
Meeting, the stockholders of the Company elected Charles C. Stephenson,
Jr. and S. Craig George as Class III Directors and John T. McNabb, II
as a Class I Director. The stockholders also considered and approved
(a) Amendment Number 5 to the Company's 1990 Stock Plan and (b) the
appointment of Arthur Andersen LLP as the independent public
accountants of the Company for the fiscal year ending December 31,
1999. The stockholders further considered and did not approve a
stockholder proposal concerning the composition of the Board of
Directors of the Company.
-31-
There were present at the Annual Meeting, in person or by proxy, stockholders
holding 43,341,089 shares of the Common Stock of the Company, or 81.61% of the
total stock outstanding and entitled to vote at the Annual Meeting. The table
below describes the results of voting at the Annual Meeting.
Votes Broker
Votes Against or Non-
For Withheld Abstentions Votes
------------ ---------- ----------- ---------
1. Election of Directors:
Charles C. Stephenson, Jr. 41,808,631 1,532,458 -0- -0-
S. Craig George 41,791,831 1,549,258 -0- -0-
John T. McNabb 41,961,641 1,379,448 -0- -0-
2. Approval of Amendment
Number 5 to the Company's
1990 Stock Plan 34,342,038 8,929,123 62,928 -0-
3. Ratification of Arthur Andersen
LLP as independent public
accountants of the Company
for fiscal 1999 43,289,236 12,064 69,928 -0-
4. Stockholder Proposal concerning
Composition of the Board of
Directors 5,135,473 30,017,810 3,191,928 4,995,878
Item 5. Other Information
-----------------
A copy of the Company's press release dated August 10, 1999,
is attached as an exhibit hereto and incorporated herein by
reference.
-32-
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
a) Exhibits
The following documents are included as exhibits to this Form
10-Q. Those exhibits below incorporated by reference herein are
indicated as such by the information supplied in the
parenthetical thereafter. If no parenthetical appears after an
exhibit, such exhibit is filed herewith.
10.1 Second Amendment to the Amended and Restated Credit
Agreement dated as of May 19, 1999, among the Company, as
borrower, and certain commercial lending institutions, as
lenders, Bank of Montreal, as administrative agent,
NationsBank, N.A., as syndication agent, and Societe
Generale, Southwest Agency, as documentation agent.
10.2 Amendment No. 5 to Vintage Petroleum, Inc., 1990 Stock
Plan dated March 16, 1999 (filed as Exhibit A to the
Company's Proxy Statement for Annual Meeting of
Stockholders dated March 31, 1999).
27. Financial data schedule.
99. Press release dated August 10, 1999, issued by the Company.
b) Reports on Form 8-K
Form 8-K was filed June 17, 1999, to report under Item 5 the
Company's May 3, 1999, filing of a registration statement on Form
S-3 with the Securities and Exchange Commission relating to the
public offering, pursuant to Rule 415 under the Securities Act of
1933, as amended, of up to an aggregate of $400,000,000 in
securities of the Company and the Company's June 16, 1999, filing
with the Securities and Exchange Commission of a supplement to
the May 3, 1999, registration statement, dated June 15, 1999,
relating to the issuance and sale in an underwritten public
offering of up to 10,350,000 shares of the Company's common
stock, par value $.005 per share.
********************************************************************************
-33-
Signatures
----------
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
VINTAGE PETROLEUM, INC.
-----------------------
(Registrant)
DATE: August 12, 1999 \s\ Michael F. Meimerstorf
----------------- ---------------------------
Michael F. Meimerstorf
Vice President and Controller
(Principal Accounting Officer)
-34-
Exhibit Index
The following documents are included as exhibits to this Form 10-Q. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, such exhibit is filed herewith.
Exhibit
Number Description
- ------ ---------------------------------------------
10.1 Second Amendment to the Amended and Restated Credit Agreement
dated as of May 19, 1999, among the Company, as borrower, and
certain commercial lending institutions, as lenders, Bank of
Montreal, as administrative agent, NationsBank, N.A., as
syndication agent, and Societe Generale, Southwest Agency, as
documentation agent.
10.2 Amendment No. 5 to Vintage Petroleum, Inc., 1990 Stock Plan dated
March 16, 1999 (filed as Exhibit A to the Company's Proxy
Statement for Annual Meeting of Stockholders dated March 31,
1999).
27. Financial Data Schedule.
99. Press release dated August 10, 1999, issued by the Company.