<PAGE> 1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[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 NO. 0-21411
============================
COSTILLA ENERGY, INC.
(Exact name of registrant as specified in its charter)
============================
DELAWARE 75-2658940
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
400 WEST ILLINOIS, SUITE 1000
MIDLAND, TEXAS 79701
(Address of principal executive offices) (Zip code)
(915) 683-3092
(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
----- ------
NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF AUGUST 13, 1999....14,101,580
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COSTILLA ENERGY, INC.
FORM 10-Q
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
PART I - FINANCIAL INFORMATION
<S> <C> <C>
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 1999 (unaudited) and
December 31, 1998........................................................ 3
Consolidated Statements of Operations for the three and six months
ended June 30, 1999 and 1998 (unaudited)................................. 4
Consolidated Statements of Cash Flows for the three and six months
ended June 30, 1999 and 1998 (unaudited)................................. 5
Notes to Consolidated Financial Statements (unaudited)..................... 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................................... 10
Item 3. Quantitative and Qualitative Disclosures About Market Risk................. 17
PART II - OTHER INFORMATION
Item 1. Legal Proceedings.......................................................... 18
Item 3. Defaults Upon Senior Securities............................................ 18
Item 5. Other Information.......................................................... 18
Item 6. Exhibits and Reports on Form 8-K........................................... 22
Signatures................................................................................... 23
</TABLE>
2
<PAGE> 3
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
COSTILLA ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
------------ ------------
ASSETS (UNAUDITED)
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 3,054 $ 5,251
Accounts receivable:
Trade, net of allowance of $158 and $180, respectively 3,889 4,547
Oil and gas sales 4,432 5,673
Prepaid and other current assets 527 1,821
------------ ------------
Total current assets 11,902 17,292
------------ ------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas properties, using the successful efforts
method of accounting:
Proved properties 160,554 275,972
Unproved properties 14,131 38,941
Accumulated depletion, depreciation and amortization (83,941) (133,612)
------------ ------------
90,744 181,301
Other property and equipment, net 3,255 4,252
------------ ------------
Total property, plant and equipment 93,999 185,553
------------ ------------
OTHER ASSETS:
Deferred charges 6,019 6,447
Other 1,690 1,662
------------ ------------
Total other assets 7,709 8,109
------------ ------------
$ 113,610 $ 210,954
============ ============
LIABILITIES AND STOCKHOLDERS' DEFICIT
CURRENT LIABILITIES:
Current maturities of long-term debt $ 29,453 $ 40,101
Trade accounts payable 7,659 26,183
Undistributed revenue 2,924 3,419
Deferred revenue 1,920 --
Other current liabilities 5,731 5,923
------------ ------------
Total current liabilities 47,687 75,626
------------ ------------
LONG-TERM DEBT, LESS CURRENT MATURITIES 181,665 181,780
------------ ------------
STOCKHOLDERS' DEFICIT:
Preferred stock, $.10 par value (3,000,000 shares authorized;
50,000 shares outstanding at June 30, 1999 and December 31, 1998) 5 5
Common stock, $.10 par value (100,000,000 shares authorized;
14,101,580 shares outstanding at June 30, 1999 and
12,751,930 shares outstanding at December 31, 1998) 1,410 1,275
Additional paid-in capital 96,030 92,715
Retained deficit (213,187) (140,447)
------------ ------------
Total stockholders' deficit (115,742) (46,452)
------------ ------------
COMMITMENTS AND CONTINGENCIES -- --
------------ ------------
$ 113,610 $ 210,954
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
3
<PAGE> 4
COSTILLA ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------ ------------------------
1999 1998 1999 1998
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
REVENUES:
Oil and gas sales $ 12,288 $ 16,670 $ 25,052 $ 32,015
Interest and other 5 155 16 360
Gain on sale of assets 253 -- 251 337
---------- ---------- ---------- ----------
12,546 16,825 25,319 32,712
---------- ---------- ---------- ----------
EXPENSES:
Oil and gas production 4,713 7,441 10,718 14,226
General and administrative 2,446 2,577 5,366 5,070
Exploration and abandonments 412 2,078 1,531 5,228
Depreciation, depletion and amortization 5,205 8,305 10,387 14,364
Loss on termination of purchase option 74 -- 47,562 --
Impairment of oil and gas properties 9,154 -- 9,154 --
Loss on commodity transactions 1,793 -- 1,793 --
Interest 5,560 5,094 10,547 9,833
---------- ---------- ---------- ----------
29,357 25,495 97,058 48,721
---------- ---------- ---------- ----------
Loss before extraordinary item (16,811) (8,670) (71,739) (16,009)
Extraordinary loss resulting from early
extinguishment of debt -- -- -- (299)
---------- ---------- ---------- ----------
NET LOSS $ (16,811) $ (8,670) $ (71,739) $ (16,308)
========== ========== ========== ==========
CUMULATIVE PREFERRED STOCK DIVIDEND $ -- $ 307 $ 1,000 $ 307
========== ========== ========== ==========
LOSS BEFORE EXTRAORDINARY ITEM
APPLICABLE TO COMMON EQUITY $ (16,811) $ (8,977) $ (72,739) $ (16,316)
========== ========== ========== ==========
NET LOSS APPLICABLE TO COMMON EQUITY $ (16,811) $ (8,977) $ (72,739) $ (16,615)
========== ========== ========== ==========
LOSS PER SHARE:
Loss before extraordinary item $ (1.20) $ (0.90) $ (5.42) $ (1.63)
Extraordinary loss resulting from early
extinguishment of debt -- -- -- (0.03)
---------- ---------- ---------- ----------
NET LOSS $ (1.20) $ (0.90) $ (5.42) $ (1.66)
========== ========== ========== ==========
WEIGHTED AVERAGE SHARES OUTSTANDING 14,025 9,981 13,423 10,027
========== ========== ========== ==========
</TABLE>
See accompanying notes to consolidated financial statements.
4
<PAGE> 5
COSTILLA ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------------- ----------------------
1999 1998 1999 1998
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
NET LOSS $ (16,811) $ (8,670) $ (71,739) $ (16,308)
ADJUSTMENTS TO RECONCILE NET LOSS TO NET
CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization 5,205 8,305 10,387 14,364
Impairment of oil and gas properties 9,154 -- 9,154 --
Exploration and abandonments 147 165 349 262
Amortization of deferred charges 156 287 312 481
Loss on termination of purchase option -- -- 46,985 --
Gain on sale of oil and gas properties (253) -- (251) (337)
Extraordinary loss resulting from early extinguishment of debt -- -- -- 299
(Gain)/loss on commodity transactions 1,793 (1) 1,793 (5)
--------- --------- --------- ---------
(609) 86 (3,010) (1,244)
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable 884 3,606 2,114 3,518
Decrease (increase) in other assets 679 276 757 54
Increase (decrease) in accounts payable (8,663) (5,662) (15,500) (7,445)
Increase (decrease) in other liabilities (4,420) (2,158) (193) 2,141
Increase (decrease) in deferred revenue (960) -- 1,920 --
--------- --------- --------- ---------
Net cash used in operating activities (13,089) (3,852) (13,912) (2,976)
--------- --------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties (1,557) (17,706) (5,175) (48,474)
Proceeds from sale of oil and gas properties 15,540 658 30,033 3,158
Additions to other property and equipment (16) (298) (43) (497)
--------- --------- --------- ---------
Net cash provided by (used in) investing activities 13,967 (17,346) 24,815 (45,813)
--------- --------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings under long-term debt 8,000 16,000 8,000 111,000
Payments of long-term debt (9,078) (29,021) (21,100) (91,541)
Proceeds from issuance of preferred stock, net -- 47,957 -- 47,957
Purchase of common stock -- -- -- (1,841)
Deferred loan and financing costs -- (123) -- (3,313)
--------- --------- --------- ---------
Net cash provided by (used in) financing activities (1,078) 34,813 (13,100) 62,262
--------- --------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (200) 13,615 (2,197) 13,473
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 3,254 3,473 5,251 3,615
--------- --------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 3,054 $ 17,088 $ 3,054 $ 17,088
========= ========= ========= =========
</TABLE>
See accompanying notes to consolidated financial statements.
5
<PAGE> 6
COSTILLA ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The interim financial information as of June 30, 1999, and for the six
months ended June 30, 1999 and 1998, is unaudited. Certain information and
footnote disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted in this Form 10-Q pursuant to the rules and regulations of the
Securities and Exchange Commission. However, in the opinion of management, these
interim financial statements include all the necessary adjustments to fairly
present the results of the interim periods and all such adjustments are of a
normal recurring nature. The interim consolidated financial statements should be
read in conjunction with the audited financial statements for the year ended
December 31, 1998.
The Company is an oil and gas exploration and production concern with
properties located principally in South and East Texas and the Permian Basin
regions of the United States.
2. DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to manage
well-defined commodity price and interest rate risks. The Company is exposed to
credit losses in the event of nonperformance by the counterparties to its
commodity hedges and its interest rate swap agreements. The Company only deals
with reputable financial institutions as counterparties and anticipates that
such counterparties will be able to fully satisfy their obligations under the
contracts. The Company does not obtain collateral or other security to support
financial instruments subject to credit risk but monitors the credit standing of
the counterparties.
Commodity Hedges. The Company utilizes swap agreements to hedge the
effect of price changes on future oil and gas production. The objective of its
hedging activities is to achieve more predictable revenues and cash flows. In a
typical swap arrangement, the Company receives the difference between a fixed
price per unit of production and a price based upon a higher agreed to third
party index. However, should the fixed price exceed the agreed third party
index, the Company has to pay the difference. In the past, the Company utilized
option contracts to hedge its production. In this case, if market prices of oil
and gas exceeded the strike price of put options, the options would expire
unexercised, therefore reducing the effective price received for oil and gas
sales by the cost of the related option. If the market prices of oil and gas
exceeded the strike price of call options, the Company would be obligated to pay
the contracting counterparty an amount equal to the contracted volumes times the
difference between the market price and the strike price, therefore reducing the
effective price received for oil and gas sales by the amount paid to the
counterparty.
The following table sets forth the future volumes hedged by year and
the strike prices of the contracts at June 30, 1999:
6
<PAGE> 7
<TABLE>
<CAPTION>
OIL GAS FIXED THRESHOLD
DAILY DAILY PRICE PRICE
VOLUME VOLUME PER PER
(BBLS) (MMBTU) BBL/MMBTU BBL/MMBTU (A)
-------- -------- --------- -------------
<S> <C> <C> <C> <C>
Oil:
July 99 - Dec. 99 2,000 -- $ 15.00 $ 13.50
Jan. 00 - Dec. 00 2,000 -- $ 16.50 $ 14.00
Gas:
July 99 - Dec. 99 (b) -- 20,000 $ 1.96 N/A
July 99 - Aug. 99 (c) -- 20,000 $ 2.10 N/A
Sept. 99 - Dec. 99 (c) -- 20,000 $ 2.30 N/A
Jan. 00 - Dec. 00 (b) -- 45,000 $ 2.20 N/A
Jan. 01 - Dec. 01 (d) -- 20,000 $ 2.30 N/A
</TABLE>
- -------------------
(a) Any trading day when the NYMEX falls below the threshold price, the
contract provides for no hedge for that day. When the NYMEX is above
the threshold price but below the fixed price, the Counterparty pays
Costilla. If the NYMEX is above the fixed price, Costilla pays the
Counterparty.
(b) In February 1999, the three year fixed price swap contract was amended
for a new period of March 1999 through December 2000 covering 45,000
Mmbtu of gas per day at a fixed price of $2.20 per Mmbtu. In February
1999 the contract for the period March 1999 through December 1999 was
liquidated resulting in cash proceeds to the Company of $3.2 million,
which has been recorded as deferred revenue and is being amortized over
the remaining term of the contract. In addition, a new contract was
entered into covering 20,000 Mmbtu of gas per day at a fixed price of
$1.96 per Mmbtu for the period March 1999 through December 1999.
(c) In April 1999, Costilla sold two calls for 20,000 Mmbtu/day.
(d) In April 1999, a swaption for the year 2001 was added. The counterparty
may elect to have Costilla cash settle all remaining payment
obligations on the last business day of each quarter from June 30, 1999
through September 30, 2000. Otherwise, notice of exercise of the Option
by the Counterparty must be provided to Costilla by December 21, 2000.
At June 30, 1999 the Company had sold one call contract which did not
qualify as a hedge and had one oil contract which resulted in a partially
overhedged position. The call contract and the overhedged portion of the oil
contract were marked-to-market at June 30, 1999 and the related liability of
$1,592,000 was recorded.
At June 30, 1999 the total liability of the Company under all hedging
arrangements, assuming the liquidation of all contracts, was approximately $11.3
million, which when combined with the amounts also incurred and past due
pursuant to these contracts as of June 30, 1999 of $0.9 million, amounted to a
total of $12.2 million. Since June 30, 1999 oil and gas prices have increased
and the total liability has therefore continued to increase.
Interest Rate Swap Agreements. The Company had an interest rate swap
agreement in place as of December 31, 1998, with a notional amount of $24
million and a fixed rate of 7.5%. The interest rate swap expired in January
1999.
7
<PAGE> 8
3. LONG TERM DEBT
In August 1997, the Company entered into a credit agreement (the
"Credit Facility") with Bankers Trust Company, as agent. The Credit Facility
provides for a maximum availability of $75.0 million, $26.9 million of which was
borrowed at June 30, 1999 against an available borrowing base of $26.9 million
at such date. For 1998 and through March 1999, borrowings under the Credit
Facility bear interest, at the Company's option, at a floating rate which was at
or above the Lender's prime or Eurodollar rate, depending on the percentage of
committed funds which had been borrowed. Beginning April 1, 1999, borrowings
bear interest at a floating rate which is a specific amount above the Lender's
prime rate. Interest is payable quarterly as to base rate loans. The Company is
in default with respect to a principal payment of $2.7 million which was due
August 10, 1999 and, in addition, does not anticipate making other scheduled
principal payments of $3.25 million which are due in August 1999. An
acceleration of all amounts due under the Credit Facility would result in an
event of default under the indenture governing the 10 1/4% Senior Notes. The
borrowing base of the Credit Facility is automatically reduced by 5% each
quarter beginning in September 1999, and payments of principal are required in
each quarter in which the outstanding principal balance is greater than the
reduced borrowing base. The remaining balance is payable on August 28, 2002, the
maturity date of the Credit Facility. Under the Credit Facility, the Company is
obligated to pay certain fees to the lender, including a commitment fee based on
the unused portion of the commitment. The Credit Facility contains customary
restrictive covenants (including restrictions on the payment of dividends and
the incurrence of additional indebtedness) and requires the Company to maintain
(i) a limit on the amount that current liabilities may exceed current assets and
(ii) a ratio of EBITDA to interest expense. Borrowings under the Credit Facility
are secured by substantially all of the assets of the Company.
In October 1996, the Company issued $100 million aggregate principal
amount of 10.25% Senior Notes due October 1, 2006 (the "Notes"). The Notes were
sold at par and interest is payable April 1 and October 1, commencing April 1,
1997. The Notes may not be redeemed prior to October 1, 2001, and thereafter at
a premium reducing to par, plus interest, by maturity. There is no mandatory
redemption of the Notes required prior to maturity. The Notes are general
unsecured senior obligations of the Company and rank equally in right of payment
with all other senior indebtedness of the Company and senior in right of payment
of all existing future subordinated indebtedness of the Company. The Notes are
subject to an Indenture between the Company and a trustee. The Indenture
restricts, among other things, the Company's ability to incur additional
indebtedness, pay dividends or make certain other restricted payments, incur
liens, engage in any sale and leaseback transaction, sell stock of subsidiaries,
apply net proceeds from certain assets sales, merge or consolidate with any
other person, sell, assign, transfer, lease, convey or otherwise dispose of
substantially all of the assets of the company, or enter into certain
transactions with affiliates. Net proceeds from the sale of the Notes of
approximately $96.1 million were used to repay existing indebtedness.
In January 1998, the Company issued an additional $80 million aggregate
principal amount of 10.25% Senior Notes due October 1, 2006 (the " 1998 Notes").
The notes were sold at a premium (102.5%) and interest is payable April 1 and
October 1, commencing April 1, 1998. The 1998 Notes may not be redeemed prior to
October 1, 2001, and thereafter at a premium reducing to par, plus interest, by
maturity. The 1998 Notes are subject to the same terms and conditions as the
Notes. Net proceeds from the sale of the 1998 Notes of approximately $78.8
million were used to repay the Credit Facility, repay an additional credit
facility and the remainder was used for general corporate working capital needs.
4. CONVERTIBLE PREFERRED STOCK
On June 3, 1998 the Company closed a private placement of 50,000 shares
of its 7% (8% Paid in Kind) Series A Cumulative Convertible Preferred Stock (the
"Preferred Stock") to Enron Capital & Trade Resources Corp. and Joint Energy
Development Investments II Limited Partnership for a purchase price of $50.0
million (the "Convertible Preferred Stock Offering"). Dividends accrue and are
payable quarterly, commencing September 15, 1998, in cash, or in certain
instances in shares of the Company's Common Stock. The dividend rate is 7% for
dividends paid in cash and 8% for dividends paid in shares of Common Stock. The
holders of the Preferred Stock may, at any time, convert shares of Preferred
Stock into shares of the Company's Common Stock at a conversion price of $11.94
which, subject to certain adjustments, would result in the issuance of 4,187,605
shares of Common Stock upon conversion of the Preferred Stock. The Company may,
at its option, redeem the shares of Preferred
8
<PAGE> 9
Stock after June 15, 2001, subject to certain limitations, for a premium
reducing to par on June 15, 2004 and thereafter. Net proceeds from the
Convertible Preferred Stock Offering were $48.0 million, of which $29.0 million
was used to repay all but $0.5 million of the Credit Facility and the remainder
for general corporate purposes.
In June 1999, the Company notified the holders of the Preferred Stock
that pursuant to the terms of Delaware General Corporation Law, the Company is
legally prohibited from paying the dividend, which was otherwise payable on June
15, 1999 on the Preferred Stock either in cash or in shares of common stock,
which constitutes an event of default. As a result, the holders of the preferred
stock have the right to increase their representation on the Company's Board of
Directors. At the present time, the holders of the Preferred Stock have not
chosen to fill either of the two directorships to which they are currently
entitled.
5. TERMINATION OF PIONEER ACQUISITION
In September 1998, Costilla entered into an agreement with Pioneer
Natural Resources USA, Inc. ("Pioneer") to acquire certain oil and gas
properties (the "Pioneer Acquisition Properties") for $410 million. As part of
this agreement, Costilla made a $25 million forfeitable deposit plus an
additional $16 million would be paid if the transaction did not close in
December 1998. In December 1998, the previous agreement was terminated and
replaced by a new agreement. Pioneer retained the $25 million deposit and
Costilla issued three million shares of its common stock and relinquished its
right to a property interest. In return, Costilla executed a new agreement to
purchase the Pioneer Acquisition Properties for $294 million. This agreement
terminated on March 31, 1999, and Costilla and Pioneer then entered into a new
agreement whereby Costilla would acquire certain of the Pioneer Acquisition
Properties for $250 million. In connection with the new agreement, the Company
issued to Pioneer one million shares of its common stock.. The new agreement
terminated by its terms on April 15, 1999 and the related costs, none of which
are recoverable, were expensed.
The loss on the termination of the Pioneer acquisition consists of the
following:
<TABLE>
<CAPTION>
(in thousands)
--------------
<S> <C>
Cash Deposit $ 25,000
4.0 million shares of Costilla common stock 13,700
Oil & gas property assigned to Pioneer 3,558
Interest capitalized for acquisition 1,012
Due diligence, legal, accounting and engineering 4,292
--------------
Total loss on termination of acquisition $ 47,562
==============
</TABLE>
6. LEGAL PROCEEDINGS
The Company is a defendant in a lawsuit styled GNK, Inc., et al v.
Costilla Energy, Inc., et al, which has recently been tried to a jury in the
87th Judicial Court of Freestone County, Texas. The case resulted from a dispute
over the ownership of certain undeveloped oil and gas leases in Freestone
County, Texas. Prior to the trial, the Company had viewed the lawsuit as
immaterial and believed that it would successfully defend the lawsuit.
Notwithstanding the Company's belief, the jury awarded actual damages in favor
of the Plaintiff and against the Company in the amount of $524,983, as well as
exemplary damages against the Company in the sum of $5,000,000. The Company has
submitted various motions, including a motion for Judgment. Notwithstanding the
verdict to the trial court and, as of the date hereof, no judgment has been
entered. The Company and its trial counsel believe that the jury's verdict was
not supported by the evidence submitted at trial and that the trial court should
grant its motion for entry of a Judgment in favor of the Company. In addition,
if the Company is forced to appeal an adverse judgment in the case, the
Company's trial counsel has advised the Company that the verdict will be
overturned on appeal.
9
<PAGE> 10
COSTILLA ENERGY, INC.
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Form 10-Q constitute "forward-looking
statements" within the meaning of the Private Securities Litigation Reform Act
of 1995 (the "Reform Act"). Such forward-looking statements involve known and
unknown risks, uncertainties, and other factors which may cause the actual
results, performance, or achievements of Costilla to be materially different
from any future results, performance, or achievements expressed or implied by
such forward-looking statements. Such factors include, among others, the
following: the volatility of oil and gas prices, the Company's drilling results
and ability to replace oil and gas reserves, the availability of capital
resources, the reliance upon estimates of proved reserves, operating hazards and
uninsured risks, competition, government regulation, and the ability of the
Company to implement its business strategy, and other factors referenced in the
Company's public filings with the Securities and Exchange Commission.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
GENERAL
Costilla is an independent energy company engaged in the exploration,
acquisition and development of oil and gas properties. From January 1, 1993 to
September 30, 1998, the Company closed nine acquisitions for an aggregate
purchase price of approximately $149.0 million. Two of those transactions
involved acquisitions from Pioneer's predecessor in 1995 and 1996 for a total
purchase price of approximately $85.0 million.
The Company is currently in default with respect to its Credit Facility
and is engaged in a comprehensive effort to reorganize its financial affairs. No
assurance can be given that the Company will be successful in this effort.
10
<PAGE> 11
The following table sets forth certain operating data of Costilla for
the periods presented:
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
1999 1998 1999 1998
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
OIL AND GAS PRODUCTION:
Oil (Mbbls) 227 505 586 1,049
Gas (Mmcf) 4,508 4,130 9,291 7,562
MMCFE (1) 5,870 7,160 12,807 13,856
AVERAGE SALES PRICES (1):
Oil (per Bbbl) $ 13.31 $ 15.42 $ 11.51 $ 15.39
Gas (per Mcf) 2.06 2.15 1.97 2.10
COSTS PER MCFE (2):
Production cost, including production taxes $ 0.80 $ 1.04 $ 0.84 $ 1.03
Production cost, excluding production taxes 0.63 0.89 0.69 0.88
Depreciation, depletion and amortization 0.89 1.16 0.81 1.04
General and administrative expenses 0.42 0.36 0.42 0.37
</TABLE>
- --------------------------------------------
(1) Before deduction of production taxes and net of any hedging results.
(2) MCFE represents equivalent Mcf of gas. In reference to oil, natural gas
equivalents are determined using the ratio of one barrel of crude oil,
condensate or natural gas liquids to six Mcf of natural gas. MMCFE
represents one thousand Mcf of gas equivalent.
Costilla uses the successful efforts method of accounting for its oil
and gas activities. Costs to acquire mineral interests in oil and gas
properties, to drill and equip exploratory wells that result in proved reserves,
and to drill and equip development wells are capitalized. Costs to drill
exploratory wells that do not result in proved reserves, geological, geophysical
and seismic costs, and costs of carrying and retaining unproved properties are
expensed. Capitalized costs of producing oil and gas properties, after
considering estimated dismantlement and abandonment costs and estimated salvage
values, are depreciated and depleted using the unit-of-production method.
Unproved oil and gas properties that are individually significant are
periodically reviewed for impairment of value, and a loss is recognized at the
time of impairment by providing an impairment allowance. Other unproved
properties are amortized based on the Company's experience of successful
drilling and average holding period.
The Company utilizes put option contracts, costless collars and swaps
to hedge the effect of price changes on a portion of its future oil and gas
production. Premiums paid and amounts receivable under the put option contracts
are amortized and accrued to oil and gas sales, respectively. If market prices
of oil and gas exceed the strike price of put options, the options will expire
unexercised, therefore, reducing the effective price received for oil and gas
sales by the cost of the related option. Conversely, if market prices of oil and
gas decline below the strike price of put options, the options will be
exercised, therefore, increasing the effective price received for oil and gas
sales by the proceeds received from the related option.
A costless collar establishes both a floor price and a ceiling for the
commodity through the simultaneous purchase of a put option contract and the
sale of a call option contract. Since the value of the put option and the call
option offset at the time of their purchase, the collar is costless, therefore
there are no premiums to amortize. If market prices of oil and gas decline below
the strike price of put options, the options will be exercised, therefore,
increasing the effective price received for oil and gas sales by the proceeds
received from the related option. Conversely, if market prices of oil and gas
exceed the strike price of call options, the Company is obligated to pay the
contracting counterparty an amount equal to the contracted volumes times the
difference between the market price and the strike price, therefore, reducing
the effective price received for oil and gas sales by the amount paid to the
counterparty.
11
<PAGE> 12
Swaps establish a fixed price for the commodity. No premiums are paid
for these price swap contracts and therefore there are no premiums to amortize.
If market prices of oil and gas decline below the swap price, the counterparty
pays the Company the difference between the swap price and the market price for
the contract volumes, therefore, increasing the effective price received for oil
and gas sales by the proceeds received under the swaps. Conversely, if market
prices of oil and gas exceed the swap price, the Company is obligated to pay the
counterparty an amount equal to the difference between the market price and the
swap price for the contract volumes, therefore, reducing the effective price
received for oil and gas sales by the amount paid to the counterparty.
The net effect of the Company's commodity hedging activities increased
oil and gas revenues by $304,000 and $2,021,000 for the three and six month
periods ended June 30, 1999 and increased oil and gas revenues by $2,700,000 and
$4,137,000 for the comparable periods in 1998. In August 1998, the Company
entered into fixed price swap contracts for the remainder of 1998 and for the
calendar year 1999 covering 5,000 Bbls of oil per day. The contracts provided
for a price of $16.40 per Bbl from January 1, 1999 through December 31, 1999.
The referenced prices were based upon the price at which WTI traded on the
NYMEX. These contracts did not provide a hedge for any trading days during the
period on which the NYMEX price for WTI closed at $13.50 or less per Bbl during
1999. In February 1999, the terms of the 1999 contract were amended to provide
for a fixed price of $15.00 per Bbl covering 5,000 Bbls of oil per day for
February 1999 through December 1999, with no hedge on any trading days during
the period when the NYMEX price for WTI closed at less than $12.00 per Bbl. In
April 1999, this swap was cancelled and replaced with another contract for 2,000
Bbls per day which provided for a price of $15.00 per Bbl for the period May
1999 through December 1999 and $16.50 per Bbl for the period January 2000
through December 2000. No hedge will be provided on any days that the NYMEX
price for WTI closes at less than $13.50 during the 1999 period and $14.00
during 2000.
In November 1998, the Company entered into fixed price swap contracts
for a period of three years, beginning January 1, 1999, covering 25,000 Mmbtu of
gas at prices of $2.40 per Mmbtu. The referenced gas price was based upon the
price at which gas trades on the NYMEX. The counterparty had certain rights to
extend the contract for up to 25,000 Mmbtu per day for up to two years through
December 2003 at the above noted price. In February 1999 the three year fixed
price swap contract was amended for a new period of March 1999 through December
2000 covering 45,000 Mmbtu of gas per day at a fixed price of $2.20 per Mmbtu.
In March, 1999, the contract for the period March 1999 through December 1999,
was liquidated resulting in cash proceeds to the Company of $3.2 million. In
addition, a new contract was entered into covering 20,000 Mmbtu of gas per day
at a fixed price of $1.96 per Mmbtu for the period March 1999 through December
1999. The referenced gas prices were based upon the price at which gas trades on
the NYMEX. In April 1999, the Company sold calls for 20,000 Mmbtu per day for
the periods May 1999 through August 1999, at a price of $2.10 per Mmbtu and
September 1999 through December 1999, at a price of $2.30 per Mmbtu. A swaption
was entered into in April for the period January 2001 through December 2001 at a
price of $2.30 per Mmbtu, which must be exercised by the Counterparty by
December 21, 2000. However, the counterparty may elect to have Costilla cash
settle on this option on the last day of any quarter from June through September
2000.
At June 30, 1999 the Company had sold one call contract which did not
qualify as a hedge and had one oil contract which resulted in a partially
overhedged position. The call contract and the overhedged portion of the oil
contract were marked-to-market at June 30, 1999 and the related liability of
$1,592,000 was recorded.
At June 30, 1999 the total liability of the Company under all hedging
arrangements, assuming the liquidation of all contracts, was approximately $11.3
million, which when combined with the amounts also incurred and past due
pursuant to these contracts as of June 30, 1999 of $0.9 million, amounted to a
total of $12.2 million. Since June 30, 1999 oil and gas prices have increased
and the total liability has therefore continued to increase.
RESULTS OF OPERATIONS
Three Months Ended June 30, 1999 Compared to Three Months Ended June 30, 1998
The Company's oil and gas revenues for the three months ended June 30,
1999 were $12,288,000, representing a decrease of $4,382,000 (26%) from revenues
of $16,670,000 in 1998. Although oil prices improved,
12
<PAGE> 13
gas prices did decline in the second quarter of 1999 so that the increase in
revenues resulting from a net increase in prices was $1,430,000 from 1998. Also,
due to property sales, oil production declined and resulted in a decrease in
revenues of $4,138,000. However, gas production increased with associated
revenues of $722,000. The average net oil price per barrel received in 1999 was
$13.31 compared to $15.42 in 1998, a 14% decrease, and the average net gas price
received in 1999 was $2.06 per Mcf compared to $2.15 in 1998, a 4% decrease.
Revenues received from oil and gas hedges were $304,000 in 1999 compared to
$2,700,000 in 1998, a $2,396,000 (89%) decrease.
Oil and gas production was 5,870 Mmcfe in 1999 compared to 7,160 Mmcfe
in 1998, an 18% decrease. Gas production increased to 4,508 Mmcf in 1999 from
4,130 Mmcf in 1998 (9%). However, oil production decreased to 227,000 Bbls in
1999 from 505,000 in 1998 (55%). The major decrease in oil production was due to
the Rocky Mountain properties that were sold which produced primarily oil.
Gains on sales of assets were produced by the Company's divestiture
plan during the quarter ended June 30, 1999. These gains consisted of the
following:
<TABLE>
<CAPTION>
Gain/(Loss)
(in thousands)
---------------
<S> <C>
Sale of miscellaneous assets $ 343
Sale of miscellaneous properties (816)
Sale of foreign operations (1,177)
Sale of Rocky Mountain properties 1,903
---------------
Total gain on sale of assets $ 253
===============
</TABLE>
Oil and gas production costs for the three month period ended June 30,
1999 were $4,713,000 ($.80 per Mcfe), compared to $7,441,000 in 1998 ($1.04 per
Mcfe), representing a decrease of $2,728,000 (37%), due principally to a
combination of lower production costs on newly completed wells and the sale of
certain oil and gas properties.
General and administrative expenses for the three months ended June 30,
1999 were $2,446,000, representing a decrease of $131,000 (5%) from 1998 of
$2,577,000. The decrease is due to a reduction in personnel and associated
expenses.
Exploration and abandonment expense decreased to $412,000 for the three
months ended June 30, 1999 compared to $2,078,000 in 1998. Dry hole and
abandonment costs decreased to $210,000 in 1999 from $1,301,000 in 1998. The
Company incurred $18,000 of seismic costs for the three months ended June 30,
1999, compared to $334,000 in the comparable period in 1998. The Company
incurred $184,000 of other geological and geophysical costs during the three
month period ended June 30, 1999 compared to $442,000 for the same period in
1998. The decrease in exploration and abandonments expense was primarily related
to the Company's curtailed drilling activities.
Depreciation, depletion and amortization ("DD&A") expense for the three
month period ended June 30, 1999 was $5,205,000 compared to $8,305,000 for 1998,
representing a decrease of $3,100,000 (37%). During the 1999 period, DD&A on oil
and gas production was provided at an average rate of $.89 per Mcfe compared to
$1.16 per Mcfe for 1998. The total decrease was a result of property sales or
less basis in remaining properties due to previous DD&A and impairments.
Impairment of oil and gas properties for the three months ended June
30, 1999, was $9,154,000 compared to none for the same period of 1998. The
impairment is primarily due to the near term expiration of acreage located in
east Texas to which proved undeveloped reserves had been assigned. The Company
does not intend to retain the acreage, and consequently impaired it at this
time.
The loss on commodity transactions for the three month period ended
June 30, 1999, was $1,793,000 compared to none for the same period of 1998. The
loss was due to the marked-to-market and the recording of a liability in the
amount of $994,000 for a gas call contract and $599,000 for the portion of the
oil contract which did not qualify as hedges. The remaining $200,000 was due to
actual losses on the non-hedge contracts.
13
<PAGE> 14
Interest expense was $5,560,000 for the three months ended June 30,
1999, compared to $5,094,000 for the comparable period in 1998. The $466,000
(9%) increase was attributable to a combination of a higher interest rate on the
bank debt and higher levels of average outstanding indebtedness. The average
amounts of applicable interest-bearing debt in 1999 and 1998 were $212,736,000
and $197,615,000, respectively. The effective annualized interest rate in 1999
was 10.5%, as compared to 10.3% in 1998.
Six months Ended June 30, 1999 Compared to Six months Ended June 30, 1998
The Company's oil and gas revenues for the six months ended June 30,
1999 were $25,052,000, representing a decrease of $6,963,000 (22%) from revenues
of $32,015,000 in 1998. Lower commodity prices accounted for a decrease in
revenues of $2,418,000. Lower oil production due to sold properties and normal
production declines caused oil sales to decrease to 586,000 Bbls in 1999 from
1,049,000 Bbls in 1998. This reduced oil revenues by $5,449,000. However, gas
production increased to 9,291,000 Mcf in 1999 from 7,562,000 Mcf in 1998, a
1,729,000 Mcf (23%) increase, which offset the above price and volume declines
by $3,020,000. Hedging revenues decreased to $2,021,000 for 1999 from $4,137,000
in 1998, a $2,116,000 decrease (51%). The average net oil price per barrel
received in 1999 was $11.51 compared to $15.39 in 1998, a 25% decrease, and the
average net gas price received in 1999 was $1.97 compared to $2.10 in 1998, a 6%
decrease. Oil and gas hedges cost $0.24 per barrel and produced revenue of $0.23
per Mcf for 1999. Revenues received from oil and gas hedges accounted for $3.57
per barrel and $0.05 per Mcf for the six months ended June 30, 1998.
Oil and gas production was 12,804 Mmcfe in 1999 compared to 13,856
Mmcfe in 1998, an 8% decrease. Oil production decreased primarily as a result of
property sales, and gas production increased due to the drilling activity
conducted in 1998.
Gain on sale of assets was $251,000 for the six months ended June 30,
1999 compared to a gain of $337,000 for 1998, representing a decrease of $86,000
(26%). For an analysis of the gains and losses during 1999, see the table
provided above in the quarterly analysis.
Oil and gas production costs for the six month period ended June 30,
1999 were $10,718,000 ($0.84 per Mcfe), compared to $14,226,000 in 1998 ($1.03
per Mcfe), representing a decrease of $3,508,000. The 25% decrease in the oil
and gas production cost per Mcfe is due principally to a combination of lower
production costs on newly completed wells in late 1998 and the sale of high cost
oil and gas properties.
General and administrative expenses for the six months ended June 30,
1999 were $5,366,000, representing an increase of $296,000 (6%) from 1998 of
$5,070,000. The increase is primarily due to an increase in bank charges and
legal fees which relate to the financial restructuring the Company is presently
undergoing.
Exploration and abandonment expense decreased to $1,531,000 for the six
months ended June 30, 1999 compared to $5,228,000 in 1998. Dry hole and
abandonment costs decreased to $583,000 in 1999 from $3,994,000 in 1998. The
Company incurred $518,000 of seismic costs for the six months ended June 30,
1999, compared to $624,000 in the comparable period in 1998. The Company
incurred $431,000 of other geological and geophysical costs during the six month
period ended June 30, 1999 compared to $610,000 for the same period in 1998. The
reduction in exploration and abandonments expense was primarily related to the
Company's decreased exploratory drilling activities in 1999 compared to 1998.
Depreciation, depletion and amortization ("DD&A") expense for the six
month period ended June 30, 1999 was $10,387,000 compared to $14,364,000 for
1998, representing a decrease of $3,977,000 (28%). During the 1999 period, DD&A
on oil and gas production was provided at an average rate of $0.81 per Mcfe
compared to $1.04 per Mcfe for 1998. The decrease was a result of property sales
or less basis in remaining properties due to previous DD&A and impairments.
Loss on termination of purchase option relates to the termination of
the Pioneer acquisition. The costs, none of which are recoverable, were
expensed. The $47,562,000 loss includes a cash payment of $25,000,000, the
relinquishment of Costilla's right to a property interest of $3,558,000,
4,000,000 shares of common stock valued at $13,700,000 and capitalized interest,
legal, accounting, engineering and due diligence costs of $5,304,000. There was
no comparable cost in 1998.
14
<PAGE> 15
Impairment of oil and gas properties for the six months ended June 30,
1999, was $9,154,000 compared to none for the same period of 1998. The
impairment is primarily due to the near term expiration of acreage located in
east Texas to which proved undeveloped reserves had been assigned. The Company
does not intend to retain the acreage, and consequently impaired it at this time
The loss on commodity transactions for the six month period ended June
30, 1999, was $1,793,000 compared to none for the same period of 1998. The loss
was due to the marked-to-market and the recording of a liability in the amount
of $994,000 for a gas call contract and $599,000 for the portion of the oil
contract which did not qualify as hedges. The remaining $200,000 was due to
actual losses on the non-hedge contracts.
Interest expense was $10,547,000 for the six months ended June 30,
1999, compared to $9,833,000 for the comparable period in 1998. The $714,000
(7%) increase was attributable to higher levels of average outstanding
indebtedness. The average amounts of applicable interest-bearing debt in 1999
and 1998 were $215,022,000 and $189,583,000, respectively. The effective
annualized interest rate in 1999 was 9.8%, as compared to 10.4% in 1998.
LIQUIDITY AND CAPITAL RESOURCES
Net Cash Provided By Operating Activities
For the six months ended June 30, 1999, net cash provided by operating
activities decreased to a negative $13.9 million from a negative $3.0 million
for 1998. Cash provided by operations, before changes in operating assets and
liabilities, decreased to a negative $3.0 million from a negative $1.2 million
for the comparable period in 1998 due primarily to lower oil and gas prices and
property sales.
Net Cash Used in Investing Activities
Net cash provided by investing activities for the six months ended June
30, 1999 was $24.8 million. Expenditures of $5.2 million were used for
exploration and development activities and $43,000 was used for other property
and equipment. Proceeds from the sale of various oil and gas properties resulted
in gross cash from investing activities of $30.0 million.
Financing Activities
For the six months ended June 30, 1999, the Company incurred $8.0
million of indebtedness under the Credit Facility which was used to pay the
April 1 interest payment to holders of its 10 1/4% Senior Notes. Proceeds
received from sales of properties and other assets were used to pay $21.1
million on the Credit Facility.
Capital Resources
On August 10, 1999 the Company failed to make a $2.7 million principal
payment required under the Credit Facility resulting in a default. The Company
has additional scheduled principal payments of $3.25 million due in August 1999,
which it does not anticipate making. The lenders may accelerate the maturity of
all amounts due under the Credit Facility which amounted to $29.2 million at
August 13, 1999. An acceleration of all amounts due under the Credit Facility
would result in an event of default under the indenture governing the 10 1/4%
Senior Notes. Any such acceleration could force the Company to seek protection
under applicable bankruptcy laws. The Company intends to continue its
discussions with the creditors and with third parties in an effort to reorganize
its financial affairs. However, no assurance can be given that its efforts will
be successful.
The Company presently has no funds available under the Credit Facility.
In March 1999, the Company sold properties previously acquired from Ballard
Petroleum LLC to the purchaser for 14.0 million. From these proceeds, $12.0
million was applied to the Credit Facility and the remainder was used for
general purposes. In the quarter ended June 30, 1999, the Company sold its Rocky
Mountain properties along with other non-essential assets for $15.5 million. Of
this amount, $9.1 million was paid on the Revolving Credit Facility.
15
<PAGE> 16
Capital Expenditures
Due to matters discussed under "Capital Resources" above, the Company
does not anticipate any significant amount of capital expenditures for 1999
until its reorganization efforts have been concluded.
Recent Accounting Pronouncements
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES - In June 1998, the FASB
issued Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133"). SFAS No. 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on a hedged
item in the income statement. Companies must formally document, designate, and
assess the effectiveness of transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15,
1999; 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 that were issued, acquired,
or substantively modified after December 31, 1997 (and, at the Company's
election, before January 1, 1998.) The Company has not yet quantified the impact
of adopting SFAS no. 133 on its financial statements and has not determined the
timing of or method of adoption of SFAS No. 133.
YEAR 2000 - The Year 2000 ("Y2K") issue is the result of computerized
systems being written to store and process the year portion of dates from and
after January 1, 2000 in a manner which may result in systems failures. Because
of the importance of occurrence dates in the oil and gas industry, the
consequences of not pursuing Y2K compliance could be significant to the
Company's ability to manage and report operating activities. During 1998, the
Company implemented a program to identify, evaluate and address Y2K risks to
ensure that the Company's Information Technology ("IT") Systems and Non-IT
Systems will be Y2K compliant. As a result, the third-party software vendor for
the Company's integrated oil and gas information system has modified the system
to accurately handle the Y2K Issue. All necessary programming modifications were
tested and updated by February 28, 1999. From a cost viewpoint, these
modifications were included in the routine updates the Company receives from its
third-party software vendor as part of the systems support contract already in
place. The Company has completed a preliminary assessment of all date-sensitive
components related to its Non-IT Systems, which primarily consist of systems
with embedded technology. Based upon this assessment, the Company has determined
that there will be minimal modification required to become Y2K compliant. The
Company will replace or modify all non-compliant Non-IT Systems as necessary.
In addition to its own informational systems, the Company may also be
effected by the Y2K compliance and readiness of third parties with whom the
Company has a material business relationship. The Company has requested that
such third parties, particularly its purchasers of production, advise the
Company concerning their Y2K compliance on or before September 30, 1999.
The Company has begun an analysis of the operational problems and costs
that would be likely to result from the failure by the Company or significant
third parties to complete efforts necessary to achieve Y2K compliance on a
timely basis. A contingency plan has not been developed for dealing with the
most likely worst case scenario, and such scenario has not yet been clearly
identified. However, included among the potential "worst case" problems the
Company could face would be the loss of electricity used to power well pumps and
compressors that would result in wells being shut-in, or the inability of a
third party gathering company or pipeline to accept oil or gas from wells or
gathering lines which could also result in wells being shut-in. A disruption in
production would result in the loss of income and delays of payments for oil and
gas sales. The risk should be minimized by the Company's efforts to communicate
with and evaluate third party compliance. The Company plans to complete such
analysis by September 30, 1999.
The Company presently does not expect to incur significant operational
problems due to the Y2K issue. However, if all Y2K issues are not properly and
timely identified, assessed, remediated and tested, both by the
16
<PAGE> 17
Company and others, there can be no assurances that the Y2K issue will not
materially impact the Company's results of operations or adversely affect
relationships with customers, vendors, or others. Additionally, there can be no
assurance that the Y2K issues of other entities will not have a material adverse
impact on the Company's systems or results of operations.
SEGMENT REPORTING - In June 1997, the FASB issued Statement of
Accounting Standards No. 131 "Disclosures about Segments of an Enterprise and
Related Information" ("FAS 131") which establishes standards for public business
enterprises for reporting information about operating segments in annual
financial statements and requires that such enterprises report selected
information about operating segments in interim financial reports issued to
shareholders. This statement also established standards for related disclosures
about products and services, geographic areas, and major customers. FAS 131 is
effective for financial statements for years beginning after December 15, 1997.
The Company operates in the one product line of oil and gas production
in limited geographic areas. This information and information about major
customers historically has been disclosed in the Company's annual financial
statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The interim information should be read and considered in conjunction
with the information included in "Quantitative and Qualitative Disclosures About
Market Risk" in Item 7A of Costilla's 1998 Annual Report on Form 10-K. Such
information includes a description of Costilla's potential exposure to market
risks, including commodity price risk, interest rate risk and foreign currency
risk. For interim information as of June 30, 1999 please see NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS, Footnote 2, Derivative Financial Instruments,
and Management's Discussion and Analysis of Financial Condition and Results of
Operations, General.
17
<PAGE> 18
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The Company is a defendant in a lawsuit styled GNK, Inc., et al v.
Costilla Energy, Inc., et al, which has recently been tried to a jury in the
87th Judicial Court of Freestone County, Texas. The case resulted from a dispute
over the ownership of certain undeveloped oil and gas leases in Freestone
County, Texas. Prior to the trial, the Company had viewed the lawsuit as
immaterial and believed that it would successfully defend the lawsuit.
Notwithstanding the Company's belief, the jury awarded actual damages in favor
of the Plaintiff and against the Company in the amount of $524,983, as well as
exemplary damages against the Company in the sum of $5,000,000. The Company has
submitted various motions, including a motion for Judgment Notwithstanding the
Verdict to the trial court and, as of the date hereof, no judgment has been
entered. The Company and its trial counsel believe that the jury's verdict was
not supported by the evidence submitted at trial and that the trial court should
grant its motion for entry of a Judgment in favor of the Company. In addition,
if the Company is forced to appeal an adverse judgment in the case, the
Company's trial counsel has advised the Company that the verdict will be
overturned on appeal.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
The Company has been unable to conclude negotiations with its secured
lenders in connection with an extension of payments due on August 10, 1999 under
its Credit Facility and, as a result, has failed to make a scheduled principal
payment of $2.7 million. In addition, the Company does not anticipate making
additional scheduled principal payments of $3.25 million due in August 1999. The
Company declined to accept a modification to its loan agreement that would have
required payment of an amendment fee out of its otherwise available cash as a
condition of obtaining an extension. The Company's bank group has not taken any
action with respect to the default, and the Company believes that any action by
the banks to accelerate the maturity of the bank debt is unlikely. However, no
assurance can be given that the bank group will not accelerate maturity of all
amounts due under the Credit Facility, which were $29.2 million at August 13,
1999. An acceleration of all amounts due under the Credit Facility would result
in an event of default under the indenture governing the 10 1/4% Senior Notes.
ITEM 5. OTHER INFORMATION
PRINCIPAL PROPERTIES
The following table sets forth certain information, as of July 1, 1999,
which relates to the principal oil and gas properties owned by the Company by
Region.
<TABLE>
<CAPTION>
PROVED RESERVES
------------------------------------------------------
TOTAL GAS PERCENT OF
GROSS OIL GAS EQUIVALENT TOTAL GAS
REGION WELLS (MBBLS) (MMCF) (MMCFE) EQUIVALENT
- ---------------------------------- -------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C>
South/East Texas.................. 464 888 84,337 89,665 77.7%
Permian Basin..................... 375 1,837 13,755 24,777 21.5
Other - Domestic.................. 26 32 752 944 0.8
-------- -------- -------- -------- --------
Total............................. 865 2,757 98,844 115,386 100%
======== ======== ======== ======== ========
</TABLE>
18
<PAGE> 19
OIL AND GAS RESERVES
The Company's estimated total proved reserves of oil and gas as of July
1, 1999 by category of proved reserves were as follows:
<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF) MMCFE
---------- ---------- ----------
<S> <C> <C> <C>
Proved developed producing.............. 2,271 62,923 76,549
Proved developed non-producing.......... 148 19,103 19,991
Proved undeveloped...................... 338 16,818 18,846
---------- ---------- ----------
Total proved.......................... 2,757 98,844 115,386
========== ========== ==========
</TABLE>
The future net cash flows from the Company's estimated proved reserves,
including the hedges in place, as of July 1, 1999 were as follows:
<TABLE>
<CAPTION>
(in thousands)
--------------
<S> <C>
Future net cash flows before income taxes................... $ 168,354
Future net cash flows before income taxes,
discounted at 10%......................................... $ 105,726
</TABLE>
The following is a reconciliation of oil and gas reserves from December
31, 1998 to June 30, 1999.
<TABLE>
<CAPTION>
OIL GAS
(MBBLS) (MMCF) MMCFE
--------- -------- ---------
<S> <C> <C> <C>
Balance, December 31, 1998 5,332 138,755 170,749
Production (586) (9,291) (12,807)
Sales of Minerals in place (3,605) (12,955) (34,586)
Purchase of Minerals in place 0 0 0
Extensions & discoveries 0 394 394
Revisions of previous estimates:
Performance 214 (22,066) (20,783)
Pricing 1,401 4,007 12,413
--------- -------- ---------
1,615 (18,059) (8,370)
--------- -------- ---------
--------- -------- ---------
Balance June 30, 1999 2,756 98,844 115,380
========= ======== =========
</TABLE>
The reserve estimates at July 1, 1999 were prepared by the Company,
while estimates at December 31, 1998 were prepared by independent petroleum
consultants.
19
<PAGE> 20
OIL AND GAS EXPENDITURES
The following table reflects costs incurred in oil and gas property
acquisition, exploration and development activities:
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30
1999
-------
<S> <C>
Property acquisition costs:
Proved $ --
Unproved 985
Exploration 1,757
Development 1,749
-------
$ 4,491
=======
</TABLE>
There are numerous uncertainties in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data set forth in this Form 10-Q are estimates only.
Although the Company believes such estimates to be reasonable, reserve estimates
are imprecise and should be expected to change as additional information becomes
available. Furthermore, estimates of oil and gas reserves, of necessity, are
projections based on engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be exactly measured, and the accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
interpretation and judgment. Accordingly, estimates of the economically
recoverable quantities of oil and gas attributable to any particular group of
properties, classifications of such reserves based on risk of recovery, and
estimates of the future net cash flows expected therefrom prepared by different
engineers or by the same engineers at different times may vary substantially.
Moreover, there can be no assurance that the reserves set forth herein will
ultimately be produced or that the proved undeveloped reserves will be developed
within the periods anticipated. Variances from the estimates contained herein
could be material. In addition, the estimates of future net revenues from proved
reserves of the Company and the present value thereof are based upon certain
assumptions about production levels, prices and costs, which may not be correct.
The Company emphasizes with respect to such estimates that the discounted future
net cash flows should not be construed as representative of the fair market
value of the proved oil and gas properties belonging to the Company, because
discounted future net cash flows are based upon projected cash flows that do not
provide for changes in oil and gas prices or for escalation of expenses and
capital costs. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based. Actual results may
differ materially from the results estimated.
The Company utilized oil and gas prices (NYMEX index) of $19.28 and
$2.33 respectively at June 30, 1999, compared to prices of $12.05 and $1.80
respectively, at December 31, 1998.
While the Company's oil and gas reserves are attributable to in excess
of 865 proved wells and locations, 39.7% of the Company's total proved reserves
at July 1, 1999 were attributable to the Southwest Speaks Field in Lavaca
County, Texas. Estimates of proved undeveloped reserves, as well as estimates
made early in the productive life of a well, may be less reliable than reserve
estimates attributable to wells which have longer production histories. Any
downward revision of the reserve estimates attributable to the Southwest Speaks
Field, or any interference in production from such Field, could have a material
adverse affect on the Company's future cash flows and financial results. Reserve
estimates attributable to the Southwest Speaks Field were revised downward by
18% at July 1, 1999 from December 31, 1998.
20
<PAGE> 21
In accordance with applicable requirements of the Securities and
Exchange Commission (the "Commission"), the estimated discounted future net
revenues from estimated proved reserves are based on prices and costs as of the
date of the estimate unless such prices or costs are contractually determined at
such date. Actual future prices and costs may be materially higher or lower.
Actual future net revenues also will be affected by factors such as actual
production, supply and demand for oil and natural gas, curtailments or increases
in consumption by natural gas purchasers, changes in governmental regulations or
taxation and the impact of inflation on costs.
21
<PAGE> 22
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
Exhibit
Number Description of Exhibit
------- ----------------------
*10.1 Ninth Amendment to Amended and Restated
Credit Agreement dated as of May 12, 1999
between Bankers Trust Company, as Agent,
Union Bank of California, N.A., as Co-Agent
and Costilla Energy, Inc.
*10.2 Tenth Amendment to Amended and Restated
Credit Agreement dated as of May 27, 1999
between Bankers Trust Company, as Agent,
Union Bank of California, N.A. as Co-Agent
and Costilla Energy, Inc.
*10.3 Eleventh Amendment to Amended and Restated
Credit Agreement dated as of June 17, 1999
between Bankers Trust company, as Agent,
Union Bank of California, N.A., as Co-Agent
and Costilla Energy, Inc.
*27.1 Financial Data Schedule
* Filed herewith
REPORTS ON FORM 8-K
The Company filed a Current Report on Form 8-K on May 11, 1999
to report under Item 5 that the Company's Chief Executive Officer had
left the Company effective April 27, 1999.
22
<PAGE> 23
S I G N A T U R E S
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.
COSTILLA ENERGY, INC.
Date: August 13, 1999 By: \s\ Bobby W. Page
---------------------------
Bobby W. Page
Senior Vice President
and Chief Financial Officer
23
<PAGE> 24
Exhibit Index
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
<S> <C>
*10.1 Ninth Amendment to Amended and Restated
Credit Agreement dated as of May 12, 1999
between Bankers Trust Company, as Agent,
Union Bank of California, N.A., as Co-Agent
and Costilla Energy, Inc.
*10.2 Tenth Amendment to Amended and Restated
Credit Agreement dated as of May 27, 1999
between Bankers Trust Company, as Agent,
Union Bank of California, N.A. as Co-Agent
and Costilla Energy, Inc.
*10.3 Eleventh Amendment to Amended and Restated
Credit Agreement dated as of June 17, 1999
between Bankers Trust company, as Agent,
Union Bank of California, N.A., as Co-Agent
and Costilla Energy, Inc.
*27.1 Financial Data Schedule
</TABLE>
* Filed herewith
<PAGE> 1
EXHIBIT 10.1
NINTH AMENDMENT TO
AMENDED AND RESTATED CREDIT AGREEMENT
This Ninth Amendment to Amended and Restated Credit Agreement
(this "Amendment") dated as of May 12, 1999 is among COSTILLA ENERGY, INC., a
Delaware corporation (the "Borrower"), the banks named on the signature pages
hereto (together with their respective successors and assigns in such capacity,
the "Banks"), BANKERS TRUST COMPANY, as agent for the Banks (together with its
successors and assigns in such capacity, the "Agent") and UNION BANK OF
CALIFORNIA, N.A., as co-agent for the Banks (together with its successors and
assigns in such capacity, the "Co-Agent").
PRELIMINARY STATEMENT
A. The Borrower and the Bank Group have entered into that
certain Amended and Restated Credit Agreement dated as of August 28, 1997 as
amended by that certain First Amendment to Amended and Restated Credit Agreement
dated as of December 30, 1997, that certain Second Amendment to Amended and
Restated Credit Agreement dated as of January 14, 1998, that certain Third
Amendment to Amended and Restated Credit Agreement dated as of February 26,
1998, that certain Fourth Amendment to Amended and Restated Credit Agreement
dated as of March 24, 1998, that certain Fifth Amendment to Amended and Restated
Credit Agreement dated as of June 30, 1998, that certain Sixth Amendment to
Amended and Restated Credit Agreement dated as of November 19, 1998, that
certain Seventh Amendment to Amended and Restated Credit Agreement dated as of
March 9, 1999 and that certain Eighth Amendment to Amended and Restated Credit
Agreement dated as of March 31, 1999 (as so amended, the "Credit Agreement").
B. The Borrower and the Bank Group desire to further amend the
Credit Agreement as set forth herein.
NOW THEREFORE, in consideration of the foregoing and the
mutual agreements set forth herein, the parties agree as follows:
Section 1. Definitions. Unless otherwise defined in this
Amendment, each capitalized term used in this Amendment has the meaning assigned
to such term in the Credit Agreement.
Section 2. Amendments. The Credit Agreement is hereby amended
as follows:
a. The second sentence of Section 2.04(a) of the Credit Agreement is
hereby amended in its entirety to read as follows:
"During the period from and after May 12, 1999 until the Borrowing Base
is redetermined in accordance with this Section (or otherwise
automatically reduced under Section 2.04(g)) the amount of the
Borrowing Base shall be $35,247,000."
b. Section 2.04(g) of the Credit Agreement is hereby amended in its
entirety to read as follows:
<PAGE> 2
"(g) In addition to the Borrowing Base redeterminations under
Section 2.04(d), on each Scheduled Loan Paydown Date set forth in
Section 2.07(b) the Borrowing Base then in effect shall be reduced by
an amount equal to the Scheduled Paydown Amount due and payable on such
Scheduled Loan Paydown Date under Section 2.07(b); provided, however if
prior to each Scheduled Loan Paydown Date all or a portion of the
Scheduled Paydown Amount due and payable on such Scheduled Loan Paydown
Date is prepaid, then (i) the Borrowing Base shall be reduced by the
amount of such prepayment on the date of such prepayment and (ii) the
Borrowing Base shall be reduced by an amount equal to the outstanding
portion of the Scheduled Paydown Amount due and payable on such
Scheduled Loan Paydown Date. "
c. Section 2.07(b) of the Credit Agreement is hereby amended in its
entirety to read as follows:
"(b) On each of the dates set forth below (each a "Scheduled
Loan Paydown Date") the Borrower shall repay the Loans comprising part
of the same Borrowing in whole or ratably in part in an amount equal to
the "Scheduled Paydown Amount" set forth opposite such Scheduled Loan
Paydown Date:
<TABLE>
<CAPTION>
Scheduled Loan Scheduled
Paydown Date Paydown Amount
------------ --------------
<S> <C>
June 1, 1999 $10,247,000
July 31, 1999 $750,000
August 15, 1999 $2,500,000
August 31, 1999 $750,000
</TABLE>
d. Section 2.09(a) of the Credit Agreement is hereby amended in its
entirety to read as follows:
"Section 2.09. Optional Prepayments. (a) The Borrower may,
from time to time on any Business Day, upon notice to the Agent stating
the proposed date and aggregate principal amount thereof, and if such
notice is given the Borrower shall, prepay the outstanding principal
amount of the Base Rate Loans (without premium or penalty) comprising
part of the same Borrowing in whole or ratably in part. The Borrower
may from time to time upon at least three Business Days' notice to the
Agent stating the proposed date and the aggregate principal amount
thereof, and if such notice is given the Borrower shall, prepay the
outstanding principal amount of the Eurodollar Rate Loans comprising
part of the same Borrowing in whole or ratably in part. So long as any
of the payments on the Loans required under Section 2.07(b) shall
remain outstanding, any such prepayment by the Borrower shall be
applied to the payments required under Section 2.07(b) in the order of
their maturity."
e. Section 6.07 of the Credit Agreement is hereby amended in its
entirety to read as follows:
"Section 6.07. Sales of Properties. The Borrower will not, and
will not permit any of its Subsidiaries to, sell, transfer, assign,
farm-out, lease or otherwise transfer or dispose of any Properties
other than (a) sales of Hydrocarbon production in the ordinary course
of
-2-
<PAGE> 3
business and sales of obsolete or worn-out equipment in the ordinary
course of business, (b) sales or transfers of Properties by any of the
Borrower's wholly-owned Subsidiaries to the Borrower or any such other
wholly-owned Subsidiary and (c) the sale of the Costilla Divestiture
Properties; provided that with respect to any such sale of Costilla
Divestiture Properties (i) the sale is consummated on or before June 1,
1999, (ii) no Default exists at the time such sale is consummated,
(iii) the cash sales proceeds received by the Borrower for each group
of Costilla Divestiture Properties is not less than the Minimum Sales
Price for such group of Costilla Divestiture Properties as set forth on
Schedule 6.07, (iv) at least 60% of the sales proceeds from such sale
is applied to partially repay the Loans and (v) the remaining sales
proceeds are applied by the Borrower toward the payment of (y) existing
Indebtedness and obligations of the Borrower and/or (z) the costs and
expenses of operating, maintaining and developing its Oil and Gas
Properties."
f. The following defined terms are hereby added to Annex A to the
Credit Agreement in their appropriate alphabetical order:
""Bone Pile Field" means the wells described on Exhibit A-1
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Chappell Lease" means the wells described on Exhibit A-2
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Circle Ridge Field" means the wells described on Exhibit A-3
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Costilla Divestiture Properties" means the Bone Pile Field,
Chappell Lease, Circle Ridge Field, Davan Unit, Hillbolt Gas Unit #1,
Johnson E and F Leases, Natural Buttes Field, Susan Peak Field, and
World Field.
"Davan Unit" means the wells described on Exhibit A-4 attached
hereto and the Oil and Gas Properties directly related or attributable
to such wells.
"Hillboldt Gas Unit #1" means the wells described on Exhibit
A-5 attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Johnson E and F Leases" means the wells described on Exhibit
A-6 attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Minimum Sales Price" means, with respect to each group of
Costilla Divestiture Properties, the minimum sales price set forth
opposite such group of Costilla Divestiture Properties on Schedule 6.07
attached hereto.
"Natural Buttes Field" means the wells described on Exhibit
A-7 attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Susan Peak Field" means the wells described on Exhibit A-8
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
-3-
<PAGE> 4
"World Field" means the wells described on Exhibit A-9
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
g. The Credit Agreement is further amended by adding the Exhibits A-1
through A-9 and Schedule 6.07 attached to this Amendment as Exhibits A-1 through
A-9 and Schedule 6.07 to the Credit Agreement.
Section 3. Limited Waiver of Credit Agreement. The Bank Group
hereby waives compliance by the Borrower with Sections 9(a) and 9(b) of the
Eighth Amendment to Amended and Restated Credit Agreement dated as of March 31,
1999 until June 1, 1999. The foregoing waiver is limited to the above described
matters and time period and shall not be construed as a waiver of any provision
of the Credit Agreement or any other Loan Document with respect to any other
matter or as a waiver of any other current or future Default or Event of Default
under the Credit Agreement. The Bank Group reserves the right to exercise any
rights or remedies with respect to any other such current or future Default or
Event of Default under the Credit Agreement.
Section 4. Limitations of Amendments. THE AMENDMENTS TO THE
CREDIT AGREEMENT SET FORTH HEREIN SHALL NOT (A) ESTABLISH A COURSE OF DEALING
BETWEEN THE BORROWER AND THE BANK GROUP, (B) BE CONSIDERED A NORMAL AND
CUSTOMARY PRACTICE BY ANY MEMBER OF THE BANK GROUP, OR (C) OBLIGATE ANY BANK TO
AGREE TO ANY OTHER AMENDMENT IN THE FUTURE FOR ANY PURPOSE. THE BORROWER FURTHER
ACKNOWLEDGES THAT THE AMENDMENTS SET FORTH HEREIN ARE AN ACCOMMODATION TO THE
BORROWER, MADE AT ITS REQUEST, AND THAT NO SIMILAR ACCOMMODATION IS PRESENTLY
CONTEMPLATED OR CAN BE EXPECTED IN THE FUTURE.
Section 5. Ratification. The Borrower hereby ratifies and
confirms all of the Obligations under the Credit Agreement (as amended hereby)
and the other Loan Documents. All references in the Loan Documents to the
"Credit Agreement" shall mean the Credit Agreement as amended hereby and as the
same may be amended, supplemented, restated or otherwise modified and in effect
from time to time in the future.
Section 6. Effectiveness. This Amendment shall become
effective in accordance with the terms of the Credit Agreement.
Section 7. Representations and Warranties. The Borrower hereby
represents and warrants to the Bank Group that (a) the execution, delivery and
performance of this Amendment has been duly authorized by all requisite
corporate action on the part of the Borrower, (b) each of the Credit Agreement
(as amended hereby) and the other Loan Documents to which it is a party
constitutes a valid and legally binding agreement enforceable against the
Borrower in accordance with its terms except, as such enforceability may be
limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent
transfer or other similar laws relating to or affecting the enforcement of
creditors' rights generally and by general principles of equity, (c) the
representations and warranties by the Borrower contained in the Credit Agreement
as amended hereby and in the other Loan Documents are true and correct on and as
of the date hereof in all material respects as though made as of the date
hereof, (d) no Default or Event of Default exists under the Credit Agreement (as
amended hereby) or any of the other Loan Documents.
-4-
<PAGE> 5
Section 8. Choice of Law. This Amendment shall be governed by,
and construed in accordance with, the laws of the State of New York.
Section 9. Final Agreement. THE CREDIT AGREEMENT (AS AMENDED
HEREBY) AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO ORAL AGREEMENTS BETWEEN
THE PARTIES.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be executed by its officers thereunto duly authorized as of the
date first above written.
COSTILLA ENERGY, INC.
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
-5-
<PAGE> 6
BANKERS TRUST COMPANY,
as Agent and Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
UNION BANK OF CALIFORNIA, N.A.,
as Co-Agent and Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
DEN NORSKE BANK ASA,
as Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
WELLS FARGO BANK (TEXAS), N.A.,
as Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
-6-
<PAGE> 7
SCHEDULE 6.07
COSTILLA DIVESTITURE PROPERTIES
<TABLE>
<CAPTION>
GROUP MINIMUM SALES PRICE
- ----- -------------------
<S> <C>
Bone Pile Field $ 249,300
Chappell Lease $ 132,300
Circle Ridge Field $ 657,900
Davan Unit $ 585,000
Hillboldt Gas Unit #1 $ 63,000
Johnson E and F Lease $ 20,700
Natural Buttes Field $ 1,462,500
Susan Peak Field $ 856,800
World Field $ 5,940,000
</TABLE>
<PAGE> 1
EXHIBIT 10.2
TENTH AMENDMENT TO
AMENDED AND RESTATED CREDIT AGREEMENT
This Tenth Amendment to Amended and Restated Credit Agreement
(this "Amendment") dated as of May 27, 1999 is among COSTILLA ENERGY, INC., a
Delaware corporation (the "Borrower"), the banks named on the signature pages
hereto (together with their respective successors and assigns in such capacity,
the "Banks"), BANKERS TRUST COMPANY, as agent for the Banks (together with its
successors and assigns in such capacity, the "Agent") and UNION BANK OF
CALIFORNIA, N.A., as co-agent for the Banks (together with its successors and
assigns in such capacity, the "Co-Agent").
PRELIMINARY STATEMENT
A. The Borrower and the Bank Group have entered into that
certain Amended and Restated Credit Agreement dated as of August 28, 1997 as
amended by that certain First Amendment to Amended and Restated Credit Agreement
dated as of December 30, 1997, that certain Second Amendment to Amended and
Restated Credit Agreement dated as of January 14, 1998, that certain Third
Amendment to Amended and Restated Credit Agreement dated as of February 26,
1998, that certain Fourth Amendment to Amended and Restated Credit Agreement
dated as of March 24, 1998, that certain Fifth Amendment to Amended and Restated
Credit Agreement dated as of June 30, 1998, that certain Sixth Amendment to
Amended and Restated Credit Agreement dated as of November 19, 1998, that
certain Seventh Amendment to Amended and Restated Credit Agreement dated as of
March 9, 1999, that certain Eighth Amendment to Amended and Restated Credit
Agreement dated as of March 31, 1999 and that certain Ninth Amendment to Amended
and Restated Credit Agreement dated as of May 12, 1999 (as so amended, the
"Credit Agreement").
B. The Borrower and the Bank Group desire to further amend the
Credit Agreement as set forth herein.
NOW THEREFORE, in consideration of the foregoing and the
mutual agreements set forth herein, the parties agree as follows:
Section 1. Definitions. Unless otherwise defined in this
Amendment, each capitalized term used in this Amendment has the meaning assigned
to such term in the Credit Agreement.
Section 2. Amendments. The Credit Agreement is hereby amended
as follows:
a. Section 2.07(b) of the Credit Agreement is hereby amended in its
entirety to read as follows:
"(b) On each of the dates set forth below (each a "Scheduled
Loan Paydown Date") the Borrower shall repay the Loans comprising part
of the same Borrowing in whole or ratably in part in an amount equal to
the "Scheduled Paydown Amount" set forth opposite such Scheduled Loan
Paydown Date:
<PAGE> 2
<TABLE>
<CAPTION>
Scheduled Loan Scheduled
Paydown Date Paydown Amount
------------ --------------
<S> <C>
June 18, 1999 $10,247,000
July 31, 1999 $750,000
August 15, 1999 $2,500,000
August 31, 1999 $750,000
</TABLE>
b. Section 6.02 of the Credit Agreement is hereby amended by adding the
following subclause (l) immediately after subclause (k) of Section 6.02:
"and (l) Liens described on Schedule 6.02 securing the
Indebtedness described on Schedule 6.02 so long as such Liens have been
released and/or extinguished on or before June 18, 1999;"
c. Section 6.07 of the Credit Agreement is hereby amended in its
entirety to read as follows:
"Section 6.07. Sales of Properties. The Borrower will not, and
will not permit any of its Subsidiaries to, sell, transfer, assign,
farm-out, lease or otherwise transfer or dispose of any Properties
other than (a) sales of Hydrocarbon production in the ordinary course
of business and sales of obsolete or worn-out equipment in the ordinary
course of business, (b) sales or transfers of Properties by any of the
Borrower's wholly-owned Subsidiaries to the Borrower or any such other
wholly-owned Subsidiary, (c) the sale of the Costilla Divestiture
Properties; provided that with respect to any such sale of Costilla
Divestiture Properties (i) the sale is consummated on or before June
18, 1999, (ii) the cash sales proceeds received by the Borrower for
each group of Costilla Divestiture Properties is not less than the
Minimum Sales Price for such group of Costilla Divestiture Properties
as set forth on Schedule 6.07, (iii) at least 60% of the sales proceeds
from such sale is applied to partially repay the Loans and (iv) the
remaining sales proceeds are applied by the Borrower toward the payment
of (y) existing Indebtedness and obligations of the Borrower and/or (z)
the costs and expenses of operating, maintaining and developing its Oil
and Gas Properties, and (d) the sale of the Rocky Mountain Divestiture
Properties; provided that with respect to any such sale of Rocky
Mountain Divestiture Properties (i) the sale is consummated on or
before June 18, 1999, (ii) the cash sales price for each group of Rocky
Mountain Divestiture Properties is not less than the Minimum Sales
Price for such group of Rocky Mountain Divestiture Properties as set
forth on Schedule 6.07, (iii) at least 60% of the cash sales proceeds
received by the Borrower at closing for each group of Rocky Mountain
Divestiture Properties is applied to partially repay the Loans, (iv)
the remaining cash sales proceeds received by the Borrower at closing
for each group of Rocky Mountain Divestiture Properties are applied by
the Borrower toward the payment of (y) existing Indebtedness and
obligations of the Borrower and/or (z) the costs and expenses of
operating, maintaining and developing its Oil and Gas Properties, (v)
the cash sales proceeds to be received by the Borrower at closing for
each group of Rocky Mountain Divestiture Properties is not less than
75% of the total cash sales price for such group of Rocky Mountain
Divestiture Properties (vi) the Agent, in its sole discretion, shall
have approved of the terms of the sale of each group of Rocky Mountain
Divestiture Properties, (vii) 100% of the cash sales proceeds received
by the Borrower after closing for each group of Rocky Mountain
Divestiture Properties is applied to partially repay the Loans
-2-
<PAGE> 3
and (viii) the Borrower shall have granted a first priority Lien in
favor of the Agent as security for the Obligations on such post-closing
cash sales proceeds and the Borrower's rights thereto pursuant to
Security Documents satisfactory in form and substance to the Agent."
d. Section 9.01 of the Credit Agreement is hereby amended in its
entirety to read as follows:
"Section 9.01. Amendments, Etc. Subject to the last sentence
of this Section 9.01, no amendment or waiver of any provision of this
Agreement, any Note or any other Loan Document, or consent to any
departure by any Person herefrom or therefrom, shall in any event be
effective unless the same shall be in writing and signed by the
Borrower and the Majority Banks, and then such waiver or consent shall
be effective only in the specific instance and for the specific purpose
for which given; provided, that no amendment, waiver or consent shall,
unless in writing and signed by all the Banks, do any of the following:
(a) waive any of the conditions specified in Article III, (b) increase
the Commitments of the Banks or subject the Banks to any additional
obligations, (c) reduce the principal of, or interest on, the Notes or
any fees or other amounts payable hereunder, (d) postpone any date
fixed for any payment of principal of, or interest on, the Notes or any
fees or other amounts payable hereunder, (e) release the Borrower or
any other Person from its payment obligations to the Bank Group,
regardless of whether such obligations are those of a primary obligor,
a guarantor or surety, or otherwise, (f) authorize the Agent to release
Liens against a substantial portion of any collateral covered by the
Security Documents, (g) take action which expressly requires the
signing of all the Banks pursuant to the terms of this Agreement, (h)
reduce the Commitment Percentages or the aggregate unpaid principal
amount of the Notes, or the number of Banks, as the case may be,
required for the Agent or the Banks or any of them to take any action
under this Agreement or reduce the percentage of Majority Banks or (i)
amend this Section 9.01; provided, further, that no amendment, waiver
or consent shall (1) unless in writing and signed by the Co-Agent in
addition to the Banks required above to take such action, effect the
rights or duties of the Co-Agent under this Agreement or any other Loan
Documents and (2) unless in writing and signed by the Agent in addition
to the Banks required above to take such action, affect the rights or
duties of the Agent under this Agreement or any other Loan Document.
Notwithstanding the foregoing, (y) the Agent may (without the consent
of the Banks) release the Lien created under the Security Documents on
any assets of the Borrower or any of its Subsidiaries if the sale of
such assets is permitted under Section 6.07 and (z) any waiver of any
Default or Event of Default under Sections 7.01(c), (d), (e), (f), (g)
or (m) or any Default that with the giving of notice or the lapse of
time or both could become an Event of Default under Sections 7.01(c),
(d), (e), (f), or (m) shall become effective for the specific instance
and for the specific purpose for which given if such waiver is in
writing and signed by the Borrower and the Required Banks."
e. The following defined terms are hereby added to Annex A to the
Credit Agreement in their appropriate alphabetical order:
"DJ Basin Field" means the wells described on Exhibit A-10
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
"Gillette Field" means the wells described on Exhibit A-11
attached hereto and the Oil and Gas Properties directly related or
attributable to such wells.
-3-
<PAGE> 4
"Required Banks" means at any time (a) the Agent, regardless
of the amounts held and (b) Banks holding at least seventy-one percent
(71%) of the then aggregate unpaid principal amount of the Loans or, if
no Loans are outstanding, Banks having Commitment Percentages in the
aggregate equal to at least seventy-one percent (71%).
"Rocky Mountain Divestiture Properties" means the DJ Basin
Field and Gillette Field."
f. Schedule 6.07 of the Credit Agreement is hereby amended in its
entirety to read the same as Schedule 6.07 attached to this Amendment.
g. The Credit Agreement is further amended by adding the Exhibits A-10
and A-11 and Schedule 6.02 attached to this Amendment as Exhibits A-10 and A-11
and Schedule 6.02 to the Credit Agreement.
Section 3. Limited Waiver of Credit Agreement. The Bank Group
hereby waives compliance by the Borrower with Sections 9(a) and 9(b) of the
Eighth Amendment to Amended and Restated Credit Agreement dated as of March 31,
1999 until June 18, 1999. The Bank Group hereby waives compliance by the
Borrower with the last sentence of Section 5.11 of the Credit Agreement until
June 18, 1999. The Bank Group hereby waives, until June 18, 1999, the Default
under Section 7.01(e) of the Credit Agreement resulting from the Borrower's
failure to pay BTCo. an amount equal to $368,900 that became due on May 5, 1999
under a certain Bank Group Derivative between the Borrower and BTCo. The
foregoing waivers are limited to the above described matters and time period,
shall expire on June 18, 1999, and shall not be construed as a waiver of any
provision of the Credit Agreement or any other Loan Document with respect to any
other matter or as a waiver of any other current or future Default or Event of
Default under the Credit Agreement. The Bank Group reserves the right to
exercise any rights or remedies with respect to any other such current or future
Default or Event of Default under the Credit Agreement. The foregoing waiver of
Section 7.01(e) of the Credit Agreement shall not be deemed as a waiver of any
right or remedy of BTCo. with respect to any Bank Group Derivative between the
Borrower and BTCo. or as a release or forgiveness by BTCo. of any amount at any
time owing by the Borrower to BTCo. in respect of any such Bank Group
Derivative.
Section 4. Limitations of Amendments. THE AMENDMENTS TO THE
CREDIT AGREEMENT AND WAIVERS SET FORTH HEREIN SHALL NOT (A) ESTABLISH A COURSE
OF DEALING BETWEEN THE BORROWER AND THE BANK GROUP, (B) BE CONSIDERED A NORMAL
AND CUSTOMARY PRACTICE BY ANY MEMBER OF THE BANK GROUP, OR (C) OBLIGATE ANY BANK
TO AGREE TO ANY OTHER AMENDMENT IN THE FUTURE FOR ANY PURPOSE. THE BORROWER
FURTHER ACKNOWLEDGES THAT THE AMENDMENTS SET FORTH HEREIN ARE AN ACCOMMODATION
TO THE BORROWER, MADE AT ITS REQUEST, AND THAT NO SIMILAR ACCOMMODATION IS
PRESENTLY CONTEMPLATED OR CAN BE EXPECTED IN THE FUTURE.
Section 5. Ratification. The Borrower hereby ratifies and
confirms all of the Obligations under the Credit Agreement (as amended hereby)
and the other Loan Documents. All references in the Loan Documents to the
"Credit Agreement" shall mean the Credit Agreement as amended hereby and as the
same may be amended, supplemented, restated or otherwise modified and in effect
from time to time in the future.
-4-
<PAGE> 5
Section 6. Effectiveness. This Amendment shall become
effective in accordance with the terms of the Credit Agreement.
Section 7. Representations and Warranties. The Borrower hereby
represents and warrants to the Bank Group that (a) the execution, delivery and
performance of this Amendment has been duly authorized by all requisite
corporate action on the part of the Borrower, (b) each of the Credit Agreement
(as amended hereby) and the other Loan Documents to which it is a party
constitutes a valid and legally binding agreement enforceable against the
Borrower in accordance with its terms except, as such enforceability may be
limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent
transfer or other similar laws relating to or affecting the enforcement of
creditors' rights generally and by general principles of equity, (c) the
representations and warranties by the Borrower contained in the Credit Agreement
as amended hereby and in the other Loan Documents are true and correct on and as
of the date hereof in all material respects as though made as of the date
hereof, (d) no Default or Event of Default exists under the Credit Agreement (as
amended hereby) or any of the other Loan Documents.
Section 8. Choice of Law. This Amendment shall be governed by,
and construed in accordance with, the laws of the State of New York.
Section 9. Final Agreement. THE CREDIT AGREEMENT (AS AMENDED
HEREBY) AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO ORAL AGREEMENTS BETWEEN
THE PARTIES.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be executed by its officers thereunto duly authorized as of the
date first above written.
COSTILLA ENERGY, INC.
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
-5-
<PAGE> 6
BANKERS TRUST COMPANY,
as Agent and Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
UNION BANK OF CALIFORNIA, N.A.,
as Co-Agent and Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
DEN NORSKE BANK ASA,
as Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
WELLS FARGO BANK (TEXAS), N.A.,
as Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
-6-
<PAGE> 7
SCHEDULE 6.02
1. Oil and Gas Lien filed by Rock Tool Company covering the Greer McKinley
#1 Well in Ward County, Texas and claiming indebtedness owed in the
amount of $69,072.14.
2. Oil and Gas Lien recorded in Volume 177, Page 629 of the real property
records of Lavaca County, Texas, filed by Steve Massey Company, Inc.
covering the Migl-Mitchell #5 Well in Lavaca County, Texas and claiming
indebtedness owed in the amount of $179,216.33.
3. Oil and Gas Liens recorded in Book 351, Page 968 of the real property
records of Eddy County and Book 370, Page 878 of the real property
records of Chavez County, New Mexico, filed by Dawson Geophysical,
covering the Harpo Prospect and claiming indebtedness owed in the
amount of $521,883.05.
<PAGE> 8
SCHEDULE 6.07
COSTILLA DIVESTITURE PROPERTIES
<TABLE>
<CAPTION>
GROUP MINIMUM SALES PRICE
- ----- -------------------
<S> <C>
Bone Pile Field $ 249,300
Chappell Lease $ 132,300
Circle Ridge Field $ 657,900
Davan Unit $ 585,000
Hillboldt Gas Unit #1 $ 63,000
Johnson E and F Lease $ 20,700
Natural Buttes Field $ 1,462,500
Susan Peak Field $ 856,800
World Field $ 5,940,000
</TABLE>
ROCKY MOUNTAIN DIVESTITURE PROPERTIES
<TABLE>
<CAPTION>
GROUP MINIMUM SALES PRICE
- ----- -------------------
<S> <C>
DJ Basin Field $ 5,500,000
Gillette Field $ 7,600,000
</TABLE>
<PAGE> 1
EXHIBIT 10.3
ELEVENTH AMENDMENT TO
AMENDED AND RESTATED CREDIT AGREEMENT
This Eleventh Amendment to Amended and Restated Credit
Agreement (this "Amendment") dated as of June 17, 1999 is among COSTILLA ENERGY,
INC., a Delaware corporation (the "Borrower"), the banks named on the signature
pages hereto (together with their respective successors and assigns in such
capacity, the "Banks"), BANKERS TRUST COMPANY, as agent for the Banks (together
with its successors and assigns in such capacity, the "Agent") and UNION BANK OF
CALIFORNIA, N.A., as co-agent for the Banks (together with its successors and
assigns in such capacity, the "Co-Agent").
PRELIMINARY STATEMENT
A. The Borrower and the Bank Group have entered into that
certain Amended and Restated Credit Agreement dated as of August 28, 1997 as
amended by that certain First Amendment to Amended and Restated Credit Agreement
dated as of December 30, 1997, that certain Second Amendment to Amended and
Restated Credit Agreement dated as of January 14, 1998, that certain Third
Amendment to Amended and Restated Credit Agreement dated as of February 26,
1998, that certain Fourth Amendment to Amended and Restated Credit Agreement
dated as of March 24, 1998, that certain Fifth Amendment to Amended and Restated
Credit Agreement dated as of June 30, 1998, that certain Sixth Amendment to
Amended and Restated Credit Agreement dated as of November 19, 1998, that
certain Seventh Amendment to Amended and Restated Credit Agreement dated as of
March 9, 1999, that certain Eighth Amendment to Amended and Restated Credit
Agreement dated as of March 31, 1999, that certain Ninth Amendment to Amended
and Restated Credit Agreement dated as of May 12, 1999 and that certain Tenth
Amendment to Amended and Restated Credit Agreement dated as of May 27, 1999 (as
so amended, the "Credit Agreement").
B. The Borrower and the Bank Group desire to further amend the
Credit Agreement as set forth herein.
NOW THEREFORE, in consideration of the foregoing and the
mutual agreements set forth herein, the parties agree as follows:
Section 1. Definitions. Unless otherwise defined in this
Amendment, each capitalized term used in this Amendment has the meaning assigned
to such term in the Credit Agreement.
Section 2. Amendments. The Credit Agreement is hereby amended
as follows:
a. The second sentence of Section 2.04(a) of the Credit Agreement is
hereby amended in its entirety to read as follows:
"During the period from and after June 17, 1999 until the
Borrower Base is redetermined in accordance with this Section (or
otherwise automatically reduced under Section 2.04(g)) the amount of
the Borrowing Base shall be $26,937,529."
<PAGE> 2
b. Section 2.07(b) of the Credit Agreement is hereby amended in its
entirety to read as follows:
"(b) On each of the dates set forth below (each a "Scheduled
Loan Paydown Date") the Borrower shall repay the Loans comprising part
of the same Borrowing in whole or ratably in part in an amount equal to
the "Scheduled Paydown Amount" set forth opposite such Scheduled Loan
Paydown Date:
<TABLE>
<CAPTION>
Scheduled Loan Scheduled
Paydown Date Paydown Amount
------------ --------------
<S> <C>
August 10, 1999 $2,687,529
August 15, 1999 $2,500,000
August 31, 1999 $750,000
</TABLE>
c. The date of "June 30, 1999" set forth in Section 4.17(b) of the
Credit Agreement is hereby amended to read "August 31, 1999."
d. Section 6.02(l) of the Credit Agreement is hereby amended in its
entirety to read as follows:
"and (l) Liens described on Schedule 6.02 securing the
Indebtedness described on Schedule 6.02 so long as such Liens have been
released and/or extinguished on or before August 10, 1999;"
e. Section 6.07 of the Credit Agreement is hereby amended in its
entirety to read as follows:
"Section 6.07. Sales of Properties. The Borrower will not, and
will not permit any of its Subsidiaries to, sell, transfer, assign,
farm-out, lease or otherwise transfer or dispose of any Properties
other than (a) sales of Hydrocarbon production in the ordinary course
of business and sales of obsolete or worn-out equipment in the ordinary
course of business, (b) sales or transfers of Properties by any of the
Borrower's wholly-owned Subsidiaries to the Borrower or any such other
wholly-owned Subsidiary, (c) the sale of the Costilla Divestiture
Properties; provided that with respect to any such sale of Costilla
Divestiture Properties (i) the sale is consummated on or before August
10, 1999, (ii) the cash sales proceeds received by the Borrower for
each group of Costilla Divestiture Properties is not less than the
Minimum Sales Price for such group of Costilla Divestiture Properties
as set forth on Schedule 6.07, (iii) at least 60% of the sales proceeds
from such sale is applied to partially repay the Loans and (iv) the
remaining sales proceeds are applied by the Borrower toward the payment
of (y) existing Indebtedness and obligations of the Borrower and/or (z)
the costs and expenses of operating, maintaining and developing its Oil
and Gas Properties, (d) the sale of the Rocky Mountain Divestiture
Properties; provided that with respect to any such sale of Rocky
Mountain Divestiture Properties
-2-
<PAGE> 3
(i) the sale is consummated on or each group of Rocky Mountain
Divestiture Properties is not less than the Minimum Sales Price for
such group of Rocky Mountain Divestiture Properties as set forth on
Schedule 6.07, (iii) at least 60% of the cash sales proceeds received
by the Borrower at closing for each group of Rocky Mountain Divestiture
Properties is applied to partially repay the Loans, (iv) the remaining
cash sales proceeds received by the Borrower at closing for each group
of Rocky Mountain Divestiture Properties are applied by the Borrower
toward the payment of (y) existing Indebtedness and obligations of the
Borrower and/or (z) the costs and expenses of operating, maintaining
and developing its Oil and Gas Properties, (v) the cash sales proceeds
to be received by the Borrower at closing for each group of Rocky
Mountain Divestiture Properties is not less than 75% of the total cash
sales price for such group of Rocky Mountain Divestiture Properties
(vi) the Agent, in its sole discretion, shall have approved of the
terms of the sale of each group of Rocky Mountain Divestiture
Properties, (vii) 100% of the cash sales proceeds received by the
Borrower after closing for each group of Rocky Mountain Divestiture
Properties is applied to partially repay the Loans and (viii) the
Borrower shall have granted a first priority Lien in favor of the Agent
as security for the Obligations on such post-closing cash sales
proceeds and the Borrower's rights thereto pursuant to Security
Documents satisfactory in form and substance to the Agent, and (e)
farmouts and leases of any of the Borrowers Oil and Gas Properties that
do not have any Proved Reserves attributable thereto so long as such
farmouts and leases are in the ordinary course of business and on terms
customary in the industry."
f. The last sentence of Section 9.01 of the Credit Agreement is hereby
amended in its entirety to read as follows:
"Notwithstanding the foregoing, (y) the Agent may (without the
consent of the Banks) release or subordinate (as appropriate) the Lien
created under the Security Documents on any assets of the Borrower or
any of its Subsidiaries if the sale, farmout or lease of such assets is
permitted under Section 6.07 and (z) any waiver of any Default or Event
of Default under Sections 7.01(c), (d), (e), (f), (g) or (m) or any
Default that with the giving of notice or the lapse of time or both
could become an Event of Default under Sections 7.01(c), (d), (e), (f),
or (m) shall become effective for the specific instance and for the
specific purpose for which given if such waiver is in writing and
signed by the Borrower and the Required Banks."
Section 3. Limited Waiver of Credit Agreement. The Bank Group
hereby waives compliance by the Borrower with Sections 9(a) and 9(b) of the
Eighth Amendment to Amended and Restated Credit Agreement dated as of March 31,
1999 until August 10, 1999. The Bank Group hereby waives compliance by the
Borrower with the last sentence of Section 5.11 of the Credit Agreement until
July 15, 1999. The Bank Group hereby waives, until August 10, 1999, the Default
under Section 7.01(e) of the Credit Agreement resulting from the Borrower's
failure to pay BTCo. (a) an amount equal to $368,900 that became due on May 5,
1999 under a certain Bank Group Derivative between the Borrower and BTCo., (b)
an amount equal to $206,640 that became due on June 3, 1999 under a certain Bank
Group Derivative between the Borrower and BTCo. and (c) an
-3-
<PAGE> 4
amount equal to $171,802 that became due on June 7, 1999 under a certain Bank
Group Derivative between the Borrower and BTCo. The Bank Group hereby waives,
until August 10, 1999, any Default that would occur under Section 7.01(e) of the
Credit Agreement resulting from the Borrower's failure to pay BTCo. any amount
that becomes due between the date of this Amendment and August 10, 1999 under
any Bank Group Derivative between the Borrower and BTCo. The Bank Group hereby
waives, until August 10, 1999, compliance by the Borrower with Sections 6.04 and
6.05 of the Credit Agreement for the calendar quarter ending June 30, 1999. The
foregoing waivers are limited to the above described matters and time period,
shall expire on August 10, 1999, and shall not be construed as a waiver of any
provision of the Credit Agreement or any other Loan Document with respect to any
other matter or as a waiver of any other current or future Default or Event of
Default under the Credit Agreement. The Bank Group reserves the right to
exercise any rights or remedies with respect to any other such current or future
Default or Event of Default under the Credit Agreement. The foregoing waiver of
Section 7.01(e) of the Credit Agreement shall not be deemed as a waiver of any
right or remedy of BTCo. with respect to any Bank Group Derivative between the
Borrower and BTCo. or as a release or forgiveness by BTCo. of any amount at any
time owing by the Borrower to BTCo. in respect of any such Bank Group
Derivative.
Section 4. Limitations of Amendments. THE AMENDMENTS TO THE
CREDIT AGREEMENT AND WAIVERS SET FORTH HEREIN SHALL NOT (A) ESTABLISH A COURSE
OF DEALING BETWEEN THE BORROWER AND THE BANK GROUP, (B) BE CONSIDERED A NORMAL
AND CUSTOMARY PRACTICE BY ANY MEMBER OF THE BANK GROUP, OR (C) OBLIGATE ANY BANK
TO AGREE TO ANY OTHER AMENDMENT OR WAIVER IN THE FUTURE FOR ANY PURPOSE. THE
BORROWER FURTHER ACKNOWLEDGES THAT THE AMENDMENTS AND WAIVERS SET FORTH HEREIN
ARE AN ACCOMMODATION TO THE BORROWER, MADE AT ITS REQUEST, AND THAT NO SIMILAR
ACCOMMODATION IS PRESENTLY CONTEMPLATED OR CAN BE EXPECTED IN THE FUTURE.
Section 5. Ratification. The Borrower hereby ratifies and
confirms all of the Obligations under the Credit Agreement (as amended hereby)
and the other Loan Documents. All references in the Loan Documents to the
"Credit Agreement" shall mean the Credit Agreement as amended hereby and as the
same may be amended, supplemented, restated or otherwise modified and in effect
from time to time in the future.
Section 6. Effectiveness. This Amendment shall become
effective in accordance with the terms of the Credit Agreement subject to the
condition precedent that the Borrower shall have paid all outstanding fees and
expenses of the Agent's counsel.
Section 7. Representations and Warranties. The Borrower hereby
represents and warrants to the Bank Group that (a) the execution, delivery and
performance of this Amendment has been duly authorized by all requisite
corporate action on the part of the Borrower, (b) each of the Credit Agreement
(as amended hereby) and the other Loan Documents to which it is a party
constitutes a valid and legally binding agreement enforceable against the
Borrower in accordance with its terms except, as such enforceability may be
limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent
transfer or other similar laws relating to or affecting the enforcement of
creditors' rights generally and by general principles of equity, (c) the
representations and warranties
-4-
<PAGE> 5
by the Borrower contained in the Credit Agreement as amended hereby and in the
other Loan Documents are true and correct on and as of the date hereof in all
material respects as though made as of the date hereof, (d) no Default or Event
of Default exists under the Credit Agreement (as amended hereby) or any of the
other Loan Documents.
Section 8. Choice of Law. This Amendment shall be governed by,
and construed in accordance with, the laws of the State of New York.
Section 9. Final Agreement. THE CREDIT AGREEMENT (AS AMENDED
HEREBY) AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE
PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO ORAL AGREEMENTS BETWEEN
THE PARTIES.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be executed by its officers thereunto duly authorized as of the
date first above written.
COSTILLA ENERGY, INC.
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
-5-
<PAGE> 6
BANKERS TRUST COMPANY,
as Agent and Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
UNION BANK OF CALIFORNIA, N.A.,
as Co-Agent and Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
DEN NORSKE BANK ASA,
as Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
WELLS FARGO BANK (TEXAS), N.A.,
as Bank
By:
--------------------------------------
Name:
------------------------------------
Title:
-----------------------------------
-6-
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS OF COSTILLA ENERGY, INC. FOR THE
QUARTER ENDED JUNE 30, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH 10-Q
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<CASH> 3,054
<SECURITIES> 0
<RECEIVABLES> 9,945
<ALLOWANCES> 842
<INVENTORY> 0
<CURRENT-ASSETS> 11,902
<PP&E> 180,315
<DEPRECIATION> 86,316
<TOTAL-ASSETS> 113,610
<CURRENT-LIABILITIES> 47,687
<BONDS> 181,665
0
5
<COMMON> 1,410
<OTHER-SE> (117,157)
<TOTAL-LIABILITY-AND-EQUITY> 113,610
<SALES> 25,052
<TOTAL-REVENUES> 25,319
<CGS> 10,718
<TOTAL-COSTS> 12,249
<OTHER-EXPENSES> 74,262
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 10,547
<INCOME-PRETAX> (71,739)
<INCOME-TAX> 0
<INCOME-CONTINUING> (71,739)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (71,739)
<EPS-BASIC> (5.42)
<EPS-DILUTED> (5.42)
</TABLE>
