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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
/XX/
Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
or
/ /
Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from ______to ______
COMMISSION FILE NO. 0-20838
CLAYTON WILLIAMS ENERGY, INC.
--------------------------------------------------------
(Exact name of Registrant as specified in its charter)
DELAWARE 75-2396863
-------------------- -----------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
6 DESTA DRIVE, SUITE 6500, MIDLAND, TEXAS 79705-5510
----------------------------------------- ----------------
(Address of principal executive offices) (Zip code)
Registrant's Telephone Number, including area code: (915) 682-6324
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 /XX/ NO / /
NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF
NOVEMBER 9, 1999.....9,106,631.
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CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
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Page
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ITEM 1. FINANCIAL STATEMENTS
Consolidated Balance Sheets as of September 30, 1999
and December 31, 1998........................................................... 3
Consolidated Statements of Operations for the three months and nine
months ended September 30, 1999 and 1998....................................... 4
Consolidated Statements of Cash Flows for the nine months
ended September 30, 1999 and 1998............................................... 5
Notes to Consolidated Financial Statements........................................ 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................................. 9
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS........................ 17
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................. 19
</TABLE>
2
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
SEPTEMBER 30, DECEMBER 31,
1999 1998
--------------- ---------------
(UNAUDITED)
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CURRENT ASSETS
Cash and cash equivalents............................................. $ 5,347 $ 1,424
Accounts receivable:
Trade, net.......................................................... 1,724 6,782
Affiliates.......................................................... 1,042 244
Oil and gas sales................................................... 8,503 3,628
Inventory............................................................. 896 1,230
Property held for resale.............................................. - 7,521
Other................................................................. 343 482
--------------- ---------------
17,855 21,311
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PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method..................... 430,996 424,360
Natural gas gathering and processing systems.......................... 9,851 8,292
Other................................................................. 10,174 10,480
--------------- ---------------
451,021 443,132
Less accumulated depreciation, depletion and amortization............. (359,088) (343,857)
--------------- ---------------
Property and equipment, net......................................... 91,933 99,275
--------------- ---------------
OTHER ASSETS............................................................. 60 67
--------------- ---------------
$ 109,848 $ 120,653
================ ================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade............................................................... $ 9,045 $ 16,384
Affiliates.......................................................... 54 65
Oil and gas sales................................................... 6,538 3,433
Current maturities of long-term debt.................................. 7,800 15,800
Accrued liabilities and other......................................... 882 1,477
--------------- ---------------
24,319 37,159
--------------- ---------------
LONG-TERM DEBT........................................................... 31,200 39,100
--------------- ---------------
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share; authorized - 3,000,000
shares; issued and outstanding - none................................ - -
Common stock, par value $.10 per share; authorized - 15,000,000
shares; issued - 8,991,437 shares in 1999 and 8,937,561
shares in 1998....................................................... 899 894
Additional paid-in capital............................................ 70,015 69,744
Retained deficit...................................................... (16,585) (26,244)
--------------- ---------------
54,329 44,394
--------------- ---------------
$ 109,848 $ 120,653
================ ================
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
3
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------------- -------------------------------
1999 1998 1999 1998
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<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales........................... $ 12,675 $ 11,479 $ 30,105 $ 42,044
Natural gas services........................ 1,061 905 2,737 2,953
------------- -------------- ------------- --------------
Total revenues............................ 13,736 12,384 32,842 44,997
------------- -------------- ------------- --------------
COSTS AND EXPENSES
Lease operations............................ 2,898 3,251 8,286 10,903
Exploration:
Abandonments and impairments.............. 1,237 1,760 2,131 7,236
Seismic and other......................... 451 823 828 2,872
Natural gas services........................ 857 806 2,313 2,515
Depreciation, depletion and amortization.... 5,081 6,881 15,921 24,707
General and administrative.................. 703 868 2,574 3,040
------------- -------------- ------------- --------------
Total costs and expenses.................. 11,227 14,389 32,053 51,273
------------- -------------- ------------- --------------
Operating income (loss)................... 2,509 (2,005) 789 (6,276)
------------- -------------- ------------- --------------
OTHER INCOME (EXPENSE)
Interest expense............................ (685) (554) (2,162) (1,539)
Gain on sales of property and equipment..... 21 20 10,614 33
Other....................................... 51 114 418 123
------------- -------------- ------------- --------------
Total other income (expense).............. (613) (420) 8,870 (1,383)
------------- -------------- ------------- --------------
INCOME (LOSS) BEFORE INCOME TAXES.............. 1,896 (2,425) 9,659 (7,659)
INCOME TAX EXPENSE............................. - - - -
------------- -------------- ------------- --------------
NET INCOME (LOSS).............................. $ 1,896 $ (2,425) $ 9,659 $ (7,659)
============= ============== ============= ==============
Net income (loss) per common share:
Basic....................................... $ .21 $ (.27) $ 1.08 $ (.86)
============= ============== ============= ==============
Diluted..................................... $ .20 $ (.27) $ 1.05 $ (.86)
============= ============== ============= ==============
Weighted average common shares outstanding:
Basic....................................... 8,986 8,907 8,971 8,897
============= ============== ============= ==============
Diluted..................................... 9,288 8,907 9,171 8,897
============= ============== ============= ==============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
4
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
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NINE MONTHS ENDED
SEPTEMBER 30,
------------------------------
1999 1998
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss).......................................................... $ 9,659 $ (7,659)
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
Depreciation, depletion and amortization............................... 15,921 24,707
Exploration costs...................................................... 2,131 7,236
Gain on sales of property and equipment................................ (10,614) (33)
Other.................................................................. 204 269
Changes in operating working capital:
Accounts receivable.................................................... (615) 5,012
Accounts payable....................................................... (1,574) (1,642)
Other.................................................................. (115) 856
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Net cash provided by operating activities......................... 14,997 28,746
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment........................................ (13,732) (38,170)
Proceeds from sales of property and equipment.............................. 18,486 79
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Net cash provided by (used in) investing activities............... 4,754 (38,091)
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt............................................... - 9,600
Repayments of long-term debt............................................... (15,900) -
Proceeds from sale of common stock......................................... 72 7
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Net cash provided by (used in) financing activities............... (15,828) 9,607
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................ 3,923 262
CASH AND CASH EQUIVALENTS
Beginning of period........................................................ 1,424 2,150
------------- -------------
End of period.............................................................. $ 5,347 $ 2,412
============= =============
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized......................... $ 2,264 $ 1,496
============= =============
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
5
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CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1999
(UNAUDITED)
1. NATURE OF OPERATIONS
Clayton Williams Energy, Inc. and its subsidiaries (collectively, the
"Company") is an independent oil and gas company engaged in the exploration for
and development and production of oil and natural gas primarily in South and
East Texas, the Texas Gulf Coast, Louisiana, Southeastern New Mexico and
Mississippi.
Substantially all of the Company's oil and gas production is sold under
short-term contracts which are market-sensitive. Accordingly, the Company's
financial condition, results of operations, and capital resources are highly
dependent upon prevailing market prices of, and demand for, oil and natural gas.
These commodity prices are subject to wide fluctuations and market uncertainties
due to a variety of factors that are beyond the control of the Company. These
factors include the level of global demand for petroleum products, foreign
supply of oil and gas, the establishment of and compliance with production
quotas by oil-exporting countries, weather conditions, the price and
availability of alternative fuels, and overall economic conditions, both foreign
and domestic. From time to time, the Company utilizes hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure to
price fluctuations (see Note 5).
2. PRESENTATION
The preparation of these consolidated financial statements in conformity
with generally accepted accounting principles requires management of the Company
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
In the opinion of management, the Company's unaudited consolidated
financial statements as of September 30, 1999 and for the interim periods ended
September 30, 1999 and 1998 include all adjustments, consisting only of normal
recurring accruals, which are necessary for a fair presentation in accordance
with generally accepted accounting principles. These interim results are not
necessarily indicative of the results to be expected for the year ending
December 31, 1999.
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. These
consolidated financial statements should be read in conjunction with the audited
consolidated financial statements and notes thereto included in the Company's
1998 Form 10-K.
3. LONG-TERM DEBT
Long-term debt consists of the following:
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SEPTEMBER 30, DECEMBER 31,
1999 1998
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(IN THOUSANDS)
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Secured Bank Credit Facility (matures July 31, 2001).............. $ 39,000 $ 54,900
Less current maturities........................................... (7,800) (15,800)
--------------- --------------
$ 31,200 $ 39,100
=============== ==============
</TABLE>
6
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The Company's secured bank credit facility (the "Credit Facility")
provides for a revolving loan facility in an amount not to exceed the lesser
of the borrowing base, as established by the banks, or that portion of the
borrowing base determined by the Company to be the elected borrowing limit.
The borrowing base, which is based on the discounted present value of future
net revenues from oil and gas production, is subject to redetermination at
any time, but at least semi-annually, and is made at the discretion of the
banks. If, at any time, the redetermined borrowing base is less than the
amount of outstanding indebtedness, the Company will be required to (i)
pledge additional collateral, (ii) prepay the excess in not more than five
equal monthly installments, or (iii) elect to convert the entire amount of
outstanding indebtedness to a term obligation based on amortization formulas
set forth in the loan agreement. Substantially all of the Company's oil and
gas properties are pledged to secure advances under the Credit Facility.
As of September 30, 1999, the borrowing base established by the banks
was $41.05 million and requires monthly commitment reductions of $650,000.
The Company has requested an increase in the borrowing base, and the banks
are presently evaluating the underlying oil and gas reserves in order to
establish a new borrowing base to be effective on or before November 30, 1999.
All outstanding balances on the Credit Facility may be designated, at
the Company's option, as either "Base Rate Loans" or "Eurodollar Loans" (as
defined in the loan agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 3/8% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin
ranging from 1.75% to 2.5% per annum. At September 30, 1999, the Company's
indebtedness under the Credit Facility consisted of $39 million of Eurodollar
Loans at a rate of 7.9%.
In addition, the Company pays the banks a commitment fee equal to 1/4%
per annum on the unused portion of the revolving loan commitment. Interest on
the revolving loan and commitment fees are payable quarterly, and all
outstanding principal and interest will be due July 31, 2001.
The loan agreement contains financial covenants that are computed
quarterly and require the Company to maintain minimum levels of working
capital, cash flow and net tangible assets. The Company was in compliance
with all of the financial covenants at September 30, 1999.
4. STOCK COMPENSATION PLANS
In May 1995, the Company's Board of Directors adopted the Executive
Incentive Stock Compensation Plan, permitting the Company to pay all or part
of selected executives' salaries in shares of common stock in lieu of cash.
The Company reserved 500,000 shares of common stock for issuance under this
plan. During the nine months ended September 30, 1999, the Company issued
31,715 shares of common stock to one officer in lieu of cash compensation
aggregating $193,708. Subsequent to September 30, 1999, the Company issued an
additional 3,631 shares to the same officer in lieu of cash compensation
aggregating $46,802. The amounts of such compensation are included in general
and administrative expense in the accompanying consolidated financial
statements.
5. FORWARD SALE TRANSACTIONS
From time to time, the Company utilizes forward sale and other
financial option arrangements, such as swaps and collars, to reduce price
risks on the sale of its oil and gas production. The Company accounts for
such arrangements as hedging activities and, accordingly, records all
realized gains and losses as oil and gas revenues in the period the hedged
production is sold. Included in oil and gas revenues during the nine month
periods ended September 30, 1999 and 1998 are losses totaling $309,000 and
net gains totaling $7,228,000 (comprised of gains of $7,381,000, partially
offset by losses of $153,000), respectively.
7
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6. PROPERTY SALES
In January 1999, the Company completed the sale of its interests in
eight non-operated oil and gas wells located in Matagorda County, Texas for
$5.2 million resulting in a gain of $1.8 million. In April 1999, the Company
also sold its interests in the Jalmat Field located in Lea County, New Mexico
for $12.5 million and recorded a gain of $8.3 million.
7. INCOME TAXES
No provisions for income tax expense were required during the periods
presented since the Company has net operating loss carryforwards available to
offset any taxable income generated during such periods. Due to the
uncertainty of realizing the related future benefits from these tax loss
carryforwards, valuation allowances were recorded at September 30, 1999 and
1998 to the extent net deferred tax assets exceed net deferred tax
liabilities.
8. RECENT ACCOUNTING PRONOUNCEMENT
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133
establishes accounting and reporting standards for derivative instruments and
hedging activities. It requires that derivatives be recognized as assets or
liabilities and measured at their fair value. SFAS 133 will be adopted in
2001 and is not expected to have a material effect on the Company's financial
condition or operations.
8
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ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Certain statements in this Form 10-Q constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933,
as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical facts, included
in this Form 10-Q that address activities, events or developments that
Clayton Williams Energy, Inc. and its subsidiaries (the "Company") expects,
projects, believes or anticipates will or may occur in the future, including
such matters as oil and gas reserves, future drilling and operations, future
production of oil and gas, future net cash flows, future capital expenditures
and other such matters, are forward-looking statements. Such forward-looking
statements involve known and unknown risks, uncertainties, and other factors
which may cause the actual results, performance, or achievements of the
Company 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, the Company's ability to replace
short-lived reserves, the availability of capital resources, the reliance
upon estimates of proved reserves, operating hazards and uninsured risks,
competition, government regulation, the ability of the Company to implement
its business strategy, and other factors referenced in this Form 10-Q.
The following discussion is intended to assist in understanding the
Company's historical consolidated financial position at September 30, 1999
and results of operations and cash flows for the periods ended September 30,
1999 and 1998. This discussion should be read in conjunction with the
Company's Form 10-K for the year ended December 31, 1998 and the consolidated
financial statements and notes thereto included in this Form 10-Q.
OVERVIEW
Prior to 1998, the Company and its predecessors concentrated their
drilling activities in the Cretaceous Trend (the "Trend") which extends from
South Texas through East Texas, Louisiana and other southern states and
includes the Austin Chalk, Buda and Georgetown formations. Oil and gas
production in the Trend is generally characterized by a high initial
production rate, followed by a steep rate of decline. In order to maintain
its oil and gas reserve base, production levels and cash flow from
operations, the Company is required to maintain or increase its level of
drilling activity and achieve comparable or improved results from such
activities. However, weak product prices caused the Company to suspend its
Trend drilling activities in April 1998. In response to recent improvements
in oil and gas prices, the Company initiated a water frac program in June
1999 in an attempt to accelerate its Trend oil production. The Company has
conducted cyclic water stimulation treatments on 15 wells to date, and plans
to stimulate approximately 16 other Austin Chalk wells by the end of the
first quarter of 2000. Daily production rates from the first 12 completed
stimulations have increased by an average of approximately 100 barrels of oil
per day over pre-stimulation levels. The Company is also currently drilling
two horizontal Austin Chalk wells in the Trend, and anticipates drilling
additional horizontal wells in this area on a well-by-well basis for the
remainder of 1999.
Beginning in 1997, the Company initiated several exploratory projects
designed to reduce its dependence on Trend drilling for future production and
reserve growth. These new areas include other formations in the vicinity of
its core properties in east central Texas, as well as South Texas, Louisiana
and Mississippi, and emphasize the development of long-life gas reserves.
During 1998, the Company devoted a substantial portion of its capital
expenditures to these new areas. Except for its Cotton Valley Pinnacle Reef
play and certain other prospects in Louisiana, the Company has no present
plans to incur any significant capital expenditures in these new areas in
1999 (see "LIQUIDITY AND CAPITAL RESOURCES - CAPITAL EXPENDITURES"). However,
the Company may farmout to industry partners its position on prospects where
exploratory drilling is warranted and attempt to retain a carried interest in
any wells drilled.
In late May 1999, the Company began selling gas from the J. C. Fazzino
Unit #1, a Cotton Valley Pinnacle Reef discovery in Robertson County, Texas.
To date, the well has produced approximately 1 Bcf of gas, net to the
Company's interest.
9
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Based upon data obtained during post-completion operations, the
Company determined that the Fazzino #1 penetrated the edge of the reef. As a
result, the Company drilled the J. C. Fazzino Unit #2 in an effort to
penetrate the core of the reef. To date, the Company has treated
approximately 550 feet of the reef and has seen encouraging gas flow rates.
The Company plans to perforate and stimulate the final section of the reef in
November 1999, and then place the well on production. Approximately 67% of
the estimated $6.5 million cost to drill and complete the Fazzino #2 is being
financed through a non-recourse vendor financing arrangement which permits
the Company to pay participating vendors for services and materials out of a
dedicated percentage of revenues from the well.
During 1998 and continuing throughout the first quarter of 1999, the
oil and gas industry operated in a depressed commodity price environment.
Anticipating the adverse effects that low product prices could have on its
capital resources, the Company initiated efforts late in 1998 to sell its
interests in two properties in order to reduce the amount of outstanding
indebtedness on the Credit Facility. In January 1999, the Company sold its
interests in eight non-operated oil and gas wells located in Matagorda
County, Texas for $5.2 million, and sold its interests in the Jalmat Field
located in Lea County, New Mexico for $12.5 million in April 1999. In the
aggregate, these properties accounted for approximately 9% of the Company's
1998 annual oil and gas production on a BOE basis and 22% of the Company's
estimated future net revenues (discounted at 10%) at December 31, 1998.
A significant portion of the Company's capital expenditures during
1998 and the first nine months of 1999 have been spent on acquisitions of
exploratory acreage, exploratory wells with limited production history, and
exploratory wells which have resulted in dry holes. Accordingly, production
from wells drilled subsequent to September 30, 1998 has not been sufficient
to offset the recent declines in oil and gas production attributable to the
temporary suspension of Trend drilling and the sales of producing properties.
Furthermore, until these new projects are completed and establish commercial
levels of production, there can be no assurance that the Company will be
successful in its efforts to replace such production declines.
The Company follows the successful efforts method of accounting for
its oil and gas properties, whereby costs of productive wells, developmental
dry holes and productive leases are capitalized and amortized using the
unit-of-production method based on estimated proved reserves. Costs of
unproved properties are initially capitalized. Those properties with
significant acquisition costs are periodically assessed, and any impairment
in value is charged to expense. The amount of impairment recognized on
unproved properties which are not individually significant is determined by
amortizing the costs of such properties within appropriate groups based on
the Company's historical experience, acquisition dates and average lease
terms. Exploration costs, including geological and geophysical expenses and
delay rentals, are charged to expense as incurred. Exploratory drilling
costs, including the cost of stratigraphic test wells, are initially
capitalized but charged to expense if and when the well is determined to be
unsuccessful.
10
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RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
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<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
1999 1998 1999 1998
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OIL AND GAS PRODUCTION DATA:
Oil (MBbls)............................ 449 570 1,398 2,066
Gas (MMcf)............................. 1,158 1,250 3,268 3,671
MBOE (1)............................... 642 778 1,943 2,678
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl)............................ $ 20.23 $ 15.32 $ 15.67 $ 16.34
Gas ($/Mcf)............................ $ 2.88 $ 2.35 $ 2.33 $ 2.38
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses............... $ 4.51 $ 4.18 $ 4.26 $ 4.07
Oil and gas depletion.................. $ 7.51 $ 8.59 $ 7.90 $ 8.96
NET WELLS DRILLED (3):
Exploratory Wells...................... .6 2.7 2.1 5.2
Developmental Wells.................... - - - 4.4
</TABLE>
- -------------
(1) Gas is converted to barrel of oil equivalents (BOE) at the ratio of six
Mcf of gas to one Bbl of oil.
(2) Includes effects of hedging transactions.
(3) Excludes wells being drilled or completed at the end of each period.
THREE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO SEPTEMBER 30, 1998
REVENUES
Oil and gas sales increased 10% from $11.5 million in 1998 to $12.7
million in 1999 due primarily to significant increases in oil and gas prices,
offset in part by a 21% decline in oil production and a 7% decline in gas
production. The decline in oil production was caused primarily by the
suspension of horizontal drilling activities in the Trend from April 1998 to
October 1999 in response to unfavorable oil prices. Gas production declined
due primarily to the loss of production from two gas properties sold in 1999,
offset in part by new production from the Cotton Valley Pinnacle Reef area.
Since the Fazzino #2 well is still in the completion and testing phase of
operations, and since the Company has just recently resumed development
activities in the Trend, production from drilling and completion activities
subsequent to September 30, 1998 has not been sufficient to offset the
decline in oil and gas production attributable to the suspension of Trend
drilling and the sales of producing properties. Furthermore, until these
wells and other exploratory projects establish and sustain commercial levels
of production, there can be no assurance that the Company will be successful
in its efforts to offset the decline in production.
The Company's average price per barrel of oil increased 32% after giving
effect to a $3.54 per barrel gain on hedging activities in the 1998 period.
Average gas prices increased 23% after giving effect to a $.21 per Mcf gain in
the 1998 period.
COSTS AND EXPENSES
Lease operations expenses decreased 12% from $3.3 million in 1998 to $2.9
million in 1999 due primarily to a combination of cost reduction measures
implemented by the Company beginning in the fourth quarter of 1998 and lower
costs attributable to the sale of two gas properties in 1999. Oil and gas
production on a BOE basis decreased 17% during the current quarter, causing an
8% increase in lease operations expenses on a BOE basis from $4.18 per BOE in
1998 to $4.51 per BOE in 1999.
11
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Exploration costs decreased 35% from $2.6 million in 1998 to $1.7
million in 1999 due primarily to substantially lower dry hole costs and
seismic costs in the 1999 period as compared to the 1998 period. Because the
Company follows the successful efforts method of accounting, the Company's
results of operations may be adversely affected during any accounting period
in which seismic costs, exploratory dry hole costs, and unproved property
impairments are expensed.
Depreciation, depletion and amortization expense decreased 26% from
$6.9 million in 1998 to $5.1 million in 1999 due primarily to a 17% decrease
in oil and gas production on a BOE basis during the 1999 quarter and, to a
lesser extent, to a 13% decline in the average depletion rate. Under the
successful efforts method of accounting, costs of oil and gas properties are
amortized on a unit-of-production method based on estimated proved reserves.
The decline in the average depletion rate per BOE from $8.59 in 1998 to $7.51
in 1999 was primarily due to higher reserve estimates attributable to
improved product prices.
General and administrative expenses declined 19% from $868,000 in 1998
to $703,000 in 1999. Beginning in December 1998, the Company implemented
certain cost reduction measures, consisting primarily of personnel layoffs
and salary reductions, in order to reduce overhead and conserve financial
resources. The effects of these efforts were offset in part by the loss of
certain overhead reimbursements associated with the sale of the Company's
interests in the Jalmat Field in April 1999.
INTEREST EXPENSE AND OTHER
Interest expense increased 24% from $554,000 in 1998 to $685,000 in
1999 due primarily to a decrease in capitalized interest from $333,000 in the
1998 period to $145,000 in the 1999 period. Gross interest expense (before
capitalization) decreased slightly due primarily to lower average levels of
indebtedness on the Credit Facility. The average daily principal balance
outstanding on such facility during the third quarter of 1999 was $39.7
million compared to $41.9 million in 1998. The effective annual interest rate
on bank debt, including bank fees, during the 1999 quarter was 8.2%, which
was comparable to the 1998 rate.
NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO SEPTEMBER 30, 1998
REVENUES
Oil and gas sales decreased 28% from $42 million in 1998 to $30.1
million in 1999 due primarily to lower oil and gas production and, to a
lesser extent, lower oil and gas prices. The 32% decline in oil production
was caused primarily by the suspension of horizontal drilling activities in
the Trend from April 1998 to October 1999 in response to unfavorable oil
prices. Gas production declined 11% due primarily to the loss of production
from two gas properties sold in 1999, offset in part by new production from
the Cotton Valley Pinnacle Reef area. Since the Fazzino #2 well is still in
the completion and testing phase of operations, and since the Company has
just recently resumed development activities in the Trend, production from
drilling and completion activities subsequent to September 30, 1998 has not
been sufficient to offset the recent declines in oil and gas production
attributable to the suspension of Trend drilling and the sales of producing
properties. Furthermore, until these wells and other exploratory projects
establish and sustain commercial levels of production, there can be no
assurance that the Company will be successful in its efforts to offset the
decline in production.
The Company's average price per barrel of oil declined 4% after giving
effect to a $.14 per barrel loss on hedging activities in the 1999 period as
compared to a $3.26 per barrel gain in the 1998 period. Average gas prices
also declined 2% after giving effect to a $.03 per Mcf hedging loss in the
1999 period as compared to a $.16 per Mcf gain in the 1998 period.
12
<PAGE>
COSTS AND EXPENSES
Lease operations expenses decreased 24% from $10.9 million in 1998 to
$8.3 million in 1999 due primarily to a combination of cost reduction
measures implemented by the Company, beginning in the fourth quarter of 1998,
and lower costs attributable to the sale of two gas properties in 1999. Oil
and gas production on a BOE basis decreased 27% during the current period,
causing a 5% increase in lease operations expenses on a BOE basis from $4.07
per BOE in 1998 to $4.26 per BOE in 1999.
Exploration costs decreased 70% from $10.1 million in 1998 to $3
million in 1999 due primarily to a combination of substantially lower dry
hole costs, impairments of unproved properties and seismic costs. Because the
Company follows the successful efforts method of accounting, the Company's
results of operations may be adversely affected during any accounting period
in which seismic costs, exploratory dry hole costs, and unproved property
impairments are expensed.
Depreciation, depletion and amortization expense decreased 36% from
$24.7 million in 1998 to $15.9 million in 1999 due primarily to a 27%
decrease in oil and gas production on a BOE basis during the 1999 period and,
to a lesser extent, to a 12% decline in the average depletion rate. Under the
successful efforts method of accounting, costs of oil and gas properties are
amortized on a unit-of-production method based on estimated proved reserves.
The decline in the average depletion rate per BOE from $8.96 in 1998 to $7.90
in 1999 was primarily due to higher reserve estimates during the second and
third quarter of 1999 attributable to improved product prices.
General and administrative expenses decreased 13% from $3 million in
1998 to $2.6 million in 1999. Beginning in December 1998, the Company
implemented certain cost reduction measures, consisting primarily of
personnel layoffs and salary reductions, in order to reduce overhead and
conserve financial resources. The effects of these efforts were offset in
part by the loss of certain overhead reimbursements associated with the sale
of the Company's interests in the Jalmat Field in April 1999.
INTEREST EXPENSE AND OTHER
Interest expense increased 47% from $1.5 million in 1998 to $2.2
million in 1999 due primarily to a combination of higher average levels of
indebtedness on the Credit Facility and a decrease in capitalized interest
from $817,000 in the 1998 period to $447,000 in the 1999 period. The average
daily principal balance outstanding on the Credit Facility during the 1999
period was $44.3 million compared to $37.7 million in 1998. The effective
annual interest rate on bank debt, including bank fees, during 1999 was 7.8%
compared to 8.2% in 1998.
During 1999, the Company recorded gains on sales of property and
equipment of $10.6 million, which included a gain of $8.3 million on the sale
of the Company's interest in the Jalmat Field located in Lea County, New
Mexico for $12.5 million, and a gain of $1.8 million on the sale of the
Company's interest in eight non-operated gas wells in Matagorda County, Texas
for $5.2 million.
13
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
The Company's primary financial resource is its oil and gas reserves.
In accordance with the terms of the Credit Facility, the banks establish a
borrowing base, as derived from the estimated value of the Company's oil and
gas properties, against which the Company may borrow funds as needed to
supplement its internally generated cash flow as a source of financing for
its capital expenditure program. Product prices, over which the Company has
very limited control, have a significant impact on such estimated value and
thereby on the Company's borrowing availability under the Credit Facility.
Within the confines of product pricing, the Company must be able to find and
develop or acquire oil and gas reserves in a cost effective manner in order
to generate sufficient financial resources through internal means to complete
the financing of its capital expenditure program.
In March 1999, the banks established the Credit Facility borrowing
base at $53 million and provided for an automatic reduction of the borrowing
base to $43 million upon sale of the Company's interests in the Jalmat Field
located in Lea County, New Mexico and further provided for monthly commitment
reductions of $650,000 beginning in July 1999. In April 1999, the Company
repaid $11.5 million of indebtedness on the Credit Facility with proceeds
from the Jalmat sale.
Although the Company had approximately $2 million available on the
Credit Facility at September 30, 1999, the monthly commitment reductions of
$650,000 will reduce the borrowing base to $39.8 million at November 30,
1999. The Company has requested an increase in the borrowing base, and the
banks are presently evaluating the underlying oil and gas reserves in order
to establish a new borrowing base to be effective on or before November 30,
1999. Depending on the amount of the adjusted borrowing base, the Company may
be required to finance a significant portion of its remaining capital
expenditures for 1999 out of internally generated cash flow.
The following discussion sets forth the Company's current plans for
capital expenditures in 1999, and the expected capital resources needed to
finance such plans.
CAPITAL EXPENDITURES
During the third quarter of 1999, the Company increased the amount it
plans to spend in 1999 on exploration and development activities from $16.9
million to $21.3 million, of which $11.4 million has been incurred through
September 30, 1999. Approximately 50% of the increase relates to additional
activities in the Company's Cotton Valley Pinnacle Reef play, and
approximately 25% is attributable to the generation of certain exploratory
prospects in Louisiana.
In response to improving product prices, the Company has initiated a
water frac program in an attempt to accelerate its Trend oil production. To
date, the Company has conducted cyclic water stimulations on 15 wells and
plans to stimulate approximately 8 additional wells during the remainder of
1999. In addition, the Company is currently drilling two horizontal Austin
Chalk wells and anticipates drilling additional horizontal wells in this area
on a well-by-well basis for the remainder of 1999. In the aggregate, the
Company plans to spend approximately $8 million on Trend development and
leasing activities, of which $3 million has been incurred through September
30, 1999.
The Company also plans to spend approximately $7.8 million on
exploration and leasing activities on the Cotton Valley Exploratory Project
in the North Giddings Field, of which $5.5 million has been incurred through
September 30, 1999. The Company has drilled two wells on one of several
Cotton Valley Pinnacle Reef anomalies identified by a 3-D seismic survey
conducted in this area in 1997. The J. C. Fazzino Unit #1 was completed in
March 1999, and the J. C. Fazzino Unit #2 is currently being completed.
The Fazzino #2 is being drilled and completed pursuant to a
non-recourse vendor financing arrangement which permits the Company to pay
participating vendors for services and materials out of a dedicated
percentage of revenue from the well. Under the terms of the agreement, the
Company will
14
<PAGE>
initially retain a net revenue interest of approximately 40% in the
production attributable to the Fazzino #2. Once the vendors have recouped the
face value of their respective invoices attributable to all wells drilled
pursuant to this agreement, plus an agreed-upon rate of return as set forth
in the agreement, the Company's net revenue interest in the Fazzino #2 will
revert to approximately 80%.
The Company completed construction of a gas pipeline and treatment
facility in May 1999. Although the pipeline can transport up to 100,000 Mcf
of gas daily, the existing treatment facility can only process up to 15,000
Mcf daily. The Company has begun constructing an additional treatment
facility with a 70,000 Mcf per day capacity at an estimated cost of $3
million. The plant is expected to be completed late in the first quarter of
2000. While the Fazzino #2 is being completed, the Company is producing the
Fazzino #1 at a current rate of approximately 11,000 Mcf per day. Once the
Fazzino #2 is placed into production, the Company may have to shut-in or
curtail production from the Fazzino #1 pending completion of the new
treatment facility.
During the third quarter of 1999, the Company completed its
interpretation of a 3-D seismic survey conducted in southwestern Louisiana.
Based on this survey, the Company has generated seven prospects on which to
conduct exploratory drilling. The Company plans to spend approximately $3
million in Louisiana on seismic, leasing and exploratory drilling activities
in 1999, of which $1.1 million has been incurred through September 30, 1999.
The remaining $2.5 million of estimated 1999 capital expenditures, of
which $1.8 million has been incurred through September 30, 1999, relate to
seismic, leasing and drilling costs on various exploratory prospects,
primarily in South and West Texas, and to development drilling costs on
existing prospects in the Texas Gulf Coast region.
The Company may increase or decrease its planned activities for 1999
depending upon drilling results, product prices, the availability of capital
resources, and other factors affecting the economic viability of such
activities.
CAPITAL RESOURCES
During the first nine months of 1999, the Company generated cash flow
from operating activities of $15 million and received proceeds from sales of
property and equipment of $18.5 million. During the same period, the Company
repaid $15.9 million on the Credit Facility and spent $13.7 million on
capital expenditures. At September 30, 1999, the Company had approximately $2
million available on the Credit Facility, as compared to $2.1 million at
December 31, 1998.
The Company's working capital deficit decreased from $15.8 million at
December 31, 1998 to $6.5 million at September 30, 1999. The Company
classified $7.8 million of its outstanding indebtedness on the Credit
Facility at September 30, 1999 as a current liability based on the required
levels of repayments, as compared to $15.8 million at December 31, 1998.
During 1998 and continuing throughout the first quarter of 1999, the
oil and gas industry operated in a depressed commodity price environment. The
effects of low product prices on the Company's capital resources were
pervasive and contributed significantly to declines in operating cash flow
and funds available on the Credit Facility. Recent improvements in product
prices have generated significant increases in operating cash flow.
Accordingly, the Company plans to utilize the additional cash flow to finance
higher levels of capital expenditures than originally projected for 1999. The
Company believes that its operating cash flow, along with any funds which may
be available on the Credit Facility, will be adequate to fund the projected
capital expenditures for 1999. However, because future cash flows and the
availability of borrowings under the Credit Facility are subject to a number
of variables, such as prevailing prices of oil and gas, actual production
from existing and newly-completed wells, the Company's success in developing
and producing new reserves, and the uncertainty with respect to the amount of
funds which may ultimately be required to finance the Company's exploration
program, there can be no assurance that the Company's capital resources will
be sufficient to sustain the Company's exploratory and development activities.
15
<PAGE>
If the Company's operating cash flow, along with any funds which may
be available on the Credit Facility, are not sufficient to fund its
anticipated levels of capital expenditures, the Company may be required to
seek alternative forms of capital resources, including the sale of assets and
the issuance of debt or equity securities. Although the Company believes it
will be able to obtain funds pursuant to one or more of these alternatives,
if needed, management cannot be assured that any such capital resources will
be available to the Company. If additional capital resources are needed, but
the Company is unable to obtain such capital resources on a timely basis, the
Company may not be able to maintain a level of liquidity sufficient to meet
its obligations as they mature or maintain compliance with the required
financial covenants contained in the Credit Facility.
INFORMATION SYSTEMS FOR THE YEAR 2000
Historically, certain computer software systems, as well as certain
hardware containing embedded chip technology, such as microcontrollers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the year
2000. This could result in system failures. The Company relies on its
computer-based management information systems, as well as embedded
technology, to operate instruments and equipment in conducting its day-to-day
business activities. Certain of these computer-based programs and embedded
technology may not have been designed to function properly with respect to
the application of dating systems relating to the year 2000.
In response, the Company has developed a "Year 2000 Plan" and, in
1998, established an internal group to identify and assess potential areas of
risk and to make any required modifications to its computer systems and
equipment used in oil and gas exploration, production, gathering and gas
processing activities. The Year 2000 Plan is comprised of various phases,
including assessment, remediation, testing and contingency plan development.
The Company believes this plan will provide reasonable assurance that its
business activities and facilities will continue to operate safely and
reliably, and without material interruption after 1999.
The Company has completed all phases of the Year 2000 Plan as it
relates to its internal systems and hardware. The Company's inventory of
computer hardware and software is substantially Year 2000 compliant. The
programming modifications for the oil and gas accounting and production
systems were completed by the software vendor in 1997 and were installed and
tested by the Company in November 1998.
The Company has monitor and control equipment with embedded chip
technology which are utilized in production and gas processing operations.
The various systems were reviewed in conjunction with the overall Year 2000
Plan and were found to be Year 2000 compliant based on manufacturers'
representations.
The Company has also undertaken to monitor the compliance efforts of
purchasers, vendors, contractors and other third parties ("Third Party
Providers") with whom it does business and whose computer-based systems
and/or embedded technology equipment interface with those of the Company to
ensure that operations will not be adversely affected by the Year 2000
compliance problems of others. There can be no assurance that there will not
be an adverse effect on the Company if Third Party Providers do not convert
their respective systems in a timely manner and in a way that is compatible
with the Company's information systems and embedded technology equipment.
However, management believes that ongoing communication with and assessment
of the compliance efforts and status of Third Party Providers will minimize
these risks. To date, the Company has been satisfied with the ability of all
significant Third Party Providers to be Year 2000 compliant on or before
December 31, 1999. If it is subsequently determined that a Third Party
Provider has failed to take the necessary action to become compliant, the
Company is confident that an alternative Third Party Provider can be selected
without any material adverse effect on the Company's operations.
To date, the costs to implement the Year 2000 Plan have been nominal
since the primary area for remediation involved software covered by a
maintenance agreement. The Company does not expect to incur any significant
costs during the remainder of 1999 to complete the Year 2000 Plan.
16
<PAGE>
Although the Company anticipates minimal business disruptions as a
result of Year 2000 issues, in the event the computer-based programs and
embedded technology equipment of the Company, or that owned and operated by
Third Party Providers, should fail to function properly, possible
consequences include, but are not limited to, loss of communication links,
inability to produce, process and sell oil and natural gas, loss of electric
power, and inability to automatically process commercial transactions or
engage in similar automated or computerized business activities.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
The Company's business is impacted by fluctuations in commodity prices
and interest rates. The following discussion is intended to identify the
nature of these market risks, describe the Company's strategy for managing
such risks, and to quantify the potential affect of market volatility on the
Company's financial condition and results of operations.
OIL AND GAS PRICES
The Company's financial condition, results of operations, and capital
resources are highly dependent upon the prevailing market prices of, and
demand for, oil and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are
beyond the control of the Company. These factors include the level of global
demand for petroleum products, foreign supply of oil and gas, the
establishment of and compliance with production quotas by oil-exporting
countries, weather conditions, the price and availability of alternative
fuels, and overall economic conditions, both foreign and domestic. It is
impossible to predict future oil and gas prices with any degree of certainty.
Sustained weakness in oil and gas prices may adversely affect the Company's
financial condition and results of operations, and may also reduce the amount
of net oil and gas reserves that the Company can produce economically. Any
reduction in reserves, including reductions due to price fluctuations, can
have an adverse affect on the Company's ability to obtain capital for its
exploration and development activities. Similarly, any improvements in oil
and gas prices can have a favorable impact on the Company's financial
condition, results of operations and capital resources. Based on the
Company's volume of oil and gas production for the nine months ended
September 30, 1999, a $1 change in the price per barrel of oil and a $.10
change in the price per Mcf of gas would result in an aggregate change in
gross revenues of approximately $1.7 million during the nine month period.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure
to price fluctuations. While the use of these hedging arrangements limits the
downside risk of price declines, such use may also limit any benefits which
may be derived from price increases. The Company uses various financial
instruments, such as swaps, collars and puts, whereby monthly settlements are
based on differences between the prices specified in the instruments and the
settlement prices of certain futures contracts quoted on the NYMEX or certain
other indices. Generally, when the applicable settlement price is less than
the price specified in the contract, the Company receives a settlement from
the counterparty based on the difference. Similarly, when the applicable
settlement price is higher than the specified price, the Company pays the
counterparty based on the difference. The instruments utilized by the Company
differ from futures contracts in that there is not a contractual obligation
which requires or permits the future physical delivery of the hedged products.
During 1998 and continuing throughout the first quarter of 1999, the
oil and gas industry operated in a depressed commodity price environment. Oil
prices during the first quarter of 1999 fell to their lowest levels in
history when adjusted for inflation. Although oil and gas prices have
improved significantly since April 1999, the commodity futures market remains
somewhat volatile and continues to reflect the uncertainties that exist
regarding near-term supply of and demand for oil and gas. In November 1997,
the Company entered into swap arrangements on a significant portion of its
1998 oil production and realized a gain of $8.8 million in 1998 on oil
hedges. In addition, the Company hedged a portion of its 1998 gas production
at various times beginning in November 1997 and realized net gains of $1.1
million in 1998 on gas hedges. As prices declined throughout 1998, the prices
at which the Company could hedge its 1999 production were generally
considered by the Company to be too low to
17
<PAGE>
effectively mitigate the downside pricing risks. However, in December 1998,
the Company purchased a floor on 800,000 barrels of oil production from
January 1999 through June 1999 at a price of $10.00 per barrel and hedged an
aggregate of 750,000 MMBtu of gas production from January 1999 through June
1999. The gas hedge was subsequently terminated at an aggregate loss of
$102,000. The Company does not have any open hedge positions as of September
30, 1999. The Company plans to enter into additional hedging arrangements
when and if the market prices for future oil and gas production improve to
favorable levels based on management's analysis of price expectations.
INTEREST RATES
All of the Company's outstanding indebtedness at September 30, 1999 is
subject to market rates of interest as determined from time to time by the
banks pursuant to the Credit Facility. See "CAPITAL RESOURCES". The Company
may designate borrowings under the Credit Facility as either "Base Rate
Loans" or "Eurodollar Loans." Base Rate Loans bear interest at a fluctuating
rate that is linked to the discount rates established by the Federal Reserve
Board. Eurodollar Loans bear interest at a fluctuating rate that is linked to
LIBOR. Any increases in these interest rates can have an adverse impact on
the Company's results of operations and cash flow. Although various financial
instruments are available to hedge the effects of changes in interest rates,
the Company does not consider the risk to be significant and has not entered
into any interest rate hedging transactions. Based on the Company's
outstanding indebtedness at September 30, 1999 of $39 million, a change in
interest rates of 25 basis points would affect annual interest payments by
approximately $98,000.
18
<PAGE>
PART II. OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
--------- ---------------------------------------------------
<S> <C>
10.1 Third Amendment to Sixth Restated Loan Agreement
dated as of August 25, 1999, among Clayton Williams
Energy, Inc., Warrior Gas Co., CWEI Acquisitions,
Inc., Bank One Texas, N.A., Paribas, and Union Bank
of California, N.A.
27 Financial Data Schedule
</TABLE>
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended
September 30, 1999.
19
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CLAYTON WILLIAMS ENERGY, INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereto duly authorized.
CLAYTON WILLIAMS ENERGY, INC.
Date: November 12, 1999 By: /s/ L. Paul Latham
----------------------------------
L. Paul Latham
Executive Vice President and Chief
Operating Officer
Date: November 12, 1999 By: /s/ Mel G. Riggs
----------------------------------
Mel G. Riggs
Senior Vice President and Chief
Financial Officer
<PAGE>
THIRD AMENDMENT TO SIXTH RESTATED LOAN AGREEMENT
THIS THIRD AMENDMENT TO SIXTH RESTATED LOAN AGREEMENT hereinafter
referred to as the "Third Amendment") executed as of the 25th day of
AUGUST, 1999, by and among CLAYTON WILLIAMS ENERGY, INC., a Delaware
corporation (the "CWE"), WARRIOR GAS CO., a Texas corporation ("Warrior ")
(CWE and Warrior being hereinafter sometimes collectively referred to as
"Borrower"), CWEI ACQUISITIONS, INC., a Delaware corporation (hereinafter
referred to as "Guarantor"), BANK ONE, TEXAS, N.A., a national banking
association ("Bank One"), PARIBAS, a French banking corporation ("Paribas")
and UNION BANK OF CALIFORNIA, N.A. ("Union"), Bank One, Paribas and Union
Bank each in their capacity as a lender hereunder together with each and
every future holder of any note issued pursuant to this Agreement are
hereinafter collectively referred to as "Banks", and individually as a
"Bank") and Bank One, as "Agent".
W I T N E S S E T H:
WHEREAS, on July 16, 1998 Borrower, Guarantor, Bank One, Paribas and
Agent entered into a Sixth Restated Loan Agreement (the "Sixth Restated"); and
WHEREAS, as of November 20, 1998, Bank One assigned to Union and
Compass Bank ("Compass") a part of its rights and obligations under the Sixth
Restated and as of such date Union and Compass became parties to the Sixth
Restated; and
WHEREAS, as of November 20, 1998, Borrower, Guarantor, Bank One,
Paribas, Union, Compass and Agent entered into a First Amendment to Sixth
Restated Loan Agreement (the "First Amendment"); and
WHEREAS, Union has acquired all of Compass' rights and obligations
under the Sixth Restated; and
WHEREAS, as of March 26, 1999, Borrower, Guarantor, Bank One, Paribas,
Union and Agent entered into a Second Amendment to Sixth Restated Loan
Agreement (the "Second Amendment"); and
WHEREAS, the Borrower and the Banks have agreed to make certain
additional changes to the Sixth Restated.
NOW, THEREFORE, the parties hereto agree as follows:
1. Unless otherwise defined herein, all defined terms used herein
shall have the same meaning ascribed to such terms in the Sixth Restated.
2. Section 13(b) of the Sixth Restated is hereby amended by adding
the following new Subsection 13(b)(ix) thereto as follows:
<PAGE>
"(ix) guarantees by CWE of loans made by third parties to CWE
employees, which loans may be extended for the sole purpose of allowing CWE
employees to exercise options to purchase CWE common stock and/or to pay
federal income tax liabilities relating from such exercise; provided,
however, that such guarantees may not exceed $1,000,000 in the aggregate
outstanding at any one time."
3. This Third Amendment shall be effective as of the date first
above written, but only upon satisfaction of the conditions precedent set
forth in Paragraph 4 hereto (the "Third Amendment Effective Date").
4. The obligations of Banks under this Third Amendment shall be
subject to the satisfaction of the following conditions precedent:
(a) EXECUTION AND DELIVERY. The Borrower shall have executed
and delivered this Third Amendment, and other required documents, all in
form and substance satisfactory to the Banks;
(b) GUARANTOR'S EXECUTION AND DELIVERY. The Guarantor shall
have executed and delivered this Third Amendment and other required
documents, all in form and substance satisfactory to the Banks;
(c) CORPORATE RESOLUTIONS. Banks shall have received
appropriate certified corporate resolutions of each Borrower and the
Guarantor;
(d) GOOD STANDING AND EXISTENCE. The Banks shall have received
evidence of existence and good standing for Borrower and the Guarantor;
(e) REPRESENTATIONS AND WARRANTIES. The representations and
warranties of Borrower under the Sixth Restated are true and correct in
all material respects as of such date, as if then made (except to the
extent that such representations and warranties related solely to an
earlier date);
(f) NO EVENT OF DEFAULT. No Event of Default shall have
occurred and be continuing nor shall any event have occurred or failed to
occur which, with the passage of time or service of notice, or both,
would constitute an Event of Default;
(g) OTHER DOCUMENTS. Each Bank shall have received such other
instruments and documents incidental and appropriate to the transaction
provided for herein as such Bank or its counsel may reasonably request,
and all such documents shall be in form and substance satisfactory to
such Bank; and
-2-
<PAGE>
(h) LEGAL MATTERS SATISFACTORY. All legal matters incident to
the consummation of the transactions contemplated hereby shall be
satisfactory to special counsel for Bank retained at the expense of
Borrower.
5. Except to the extent its provisions are specifically amended,
modified or superseded by this Third Amendment, the representations,
warranties and affirmative and negative covenants of the Borrower contained
in the Sixth Restated are incorporated herein by reference for all purposes
as if copied herein in full. The Borrower hereby restates and reaffirms each
and every term and provision of the Sixth Restated, as amended, including,
without limitation, all representations, warranties and affirmative and
negative covenants. Except to the extent its provisions are specifically
amended, modified or superseded by this Third Amendment, the Sixth Restated,
as amended, and all terms and provisions thereof shall remain in full force
and effect, and the same in all respects are confirmed and approved by the
Borrower and the Banks.
6. This Third Amendment may be executed in any number of
counterparts and all of such counterparts taken together shall be deemed to
constitute one and the same instrument.
7. The Guarantor hereby consents to the execution of this Third
Amendment by the Borrower and reaffirms its guaranty of all of the
obligations of the Borrower to the Bank. Borrower and Guarantor acknowledge
and agree that the renewal, extension and amendment of the Loan Agreement
shall not be considered a novation of account or new contract but that all
existing rights, titles, powers, Liens, security interests and estates in
favor of the Banks constitute valid and existing obligations and Liens and
security interests as against the Collateral in favor of the Banks. Borrower
and Guarantor confirm and agree that (a) neither the execution of this Third
Amendment or any other Loan Document nor the consummation of the transactions
described herein and therein shall in any way effect, impair or limit the
covenants, liabilities, obligations and duties of the Borrower and under the
Loan Documents and (b) the obligations evidenced and secured by the Loan
Documents continue in full force and effect. Guarantor hereby further
confirms that it unconditionally guarantees to the extent set forth in its
Guaranty the due and punctual payment and performance of any and all amounts
and obligations owed by the Banks under the Sixth Restated or the other Loan
Documents.
IN WITNESS WHEREOF, the parties have caused this Third Amendment to
Sixth Restated to be duly executed as of the date first above written.
BORROWER:
CLAYTON WILLIAMS ENERGY, INC.
a Delaware corporation
By: /s/ L. PAUL LATHAM
-----------------------------------
L. Paul Latham, Executive Vice
President
-3-
<PAGE>
WARRIOR GAS CO.
a Delaware corporation
By: /s/ L. PAUL LATHAM
-----------------------------------
L. Paul Latham, Vice President
GUARANTOR:
CWEI ACQUISITIONS, INC.
a Delaware corporation
By: /s/ L. PAUL LATHAM
-----------------------------------
L. Paul Latham, Vice President
AGENT:
BANK ONE, TEXAS, N.A.
a national banking association
By: /s/ WM. MARK CRANMER
-----------------------------------
Wm. Mark Cranmer, Vice President
BANKS:
BANK ONE, TEXAS, N.A.
a national banking association
By: /s/ WM. MARK CRANMER
-----------------------------------
Wm. Mark Cranmer, Vice President
-4-
<PAGE>
PARIBAS
a French banking corporation
By: /s/ MARIAN LIVINGSTON
-----------------------------------
Marian Livingston, Vice President
By: /s/ BETSY JOCHER
-----------------------------------
Betsy Jocher, Vice President
UNION BANK OF CALIFORNIA, N.A.
By: /s/ JOHN A. CLARK
-----------------------------------
John A. Clark, Vice President
By: /s/ GARY SHEKERJIAN
-----------------------------------
Gary Shekerjian, Assistant Vice President
-5-
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS OF THE REGISTRANT FOR THE QUARTER ENDED
SEPTEMBER 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 5,347
<SECURITIES> 0
<RECEIVABLES> 11,269
<ALLOWANCES> 0
<INVENTORY> 896
<CURRENT-ASSETS> 17,855
<PP&E> 451,021
<DEPRECIATION> (359,088)
<TOTAL-ASSETS> 109,848
<CURRENT-LIABILITIES> 24,319
<BONDS> 31,200
0
0
<COMMON> 899
<OTHER-SE> 53,430
<TOTAL-LIABILITY-AND-EQUITY> 109,848
<SALES> 30,105
<TOTAL-REVENUES> 32,842
<CGS> 8,286
<TOTAL-COSTS> 32,053
<OTHER-EXPENSES> (11,032)<F1>
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,162
<INCOME-PRETAX> 9,659
<INCOME-TAX> 0
<INCOME-CONTINUING> 9,659
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,659
<EPS-BASIC> 1.08
<EPS-DILUTED> 1.05
<FN>
<F1>INCLUDES $10.6 MILLION GAINS ON SALE OF PROPERTY AND EQUIPMENT.
</FN>
</TABLE>
