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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, 1998
or
/ / Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from _______ to _______
COMMISSION FILE 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 10, 1998...8,923,910
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CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
<TABLE>
<CAPTION>
ITEM 1. FINANCIAL STATEMENTS PAGE
----
<S> <C> <C>
Consolidated Balance Sheets as of September 30, 1998
and December 31, 1997............................................................. 3
Consolidated Statements of Operations for the three months and nine months
ended September 30, 1998 and 1997................................................ 4
Consolidated Statements of Cash Flows for the nine months
ended September 30, 1998 and 1997................................................. 5
Notes to Consolidated Financial Statements.......................................... 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................................... 9
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................... 16
</TABLE>
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2
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1998 1997
--------------- --------------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents............................................. $ 2,412 $ 2,150
Accounts receivable:
Trade, net.......................................................... 1,982 4,197
Affiliates.......................................................... 798 173
Oil and gas sales................................................... 5,704 9,126
Inventory............................................................. 1,562 2,530
Other................................................................. 682 1,243
------------ --------------
13,140 19,419
------------ --------------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method..................... 437,892 412,352
Natural gas gathering and processing systems.......................... 7,994 7,869
Other................................................................. 10,638 10,411
------------ --------------
456,524 430,632
Less accumulated depreciation, depletion and amortization............. (340,077) (315,559)
------------ --------------
Property and equipment, net......................................... 116,447 115,073
------------ --------------
OTHER ASSETS............................................................. 56 70
------------ --------------
$ 129,643 $ 134,562
=========== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade............................................................... $ 12,548 $ 16,480
Affiliates.......................................................... 94 603
Oil and gas sales................................................... 5,113 7,679
Current maturities of long-term debt.................................. - 42
Accrued liabilities and other......................................... 897 984
------------ --------------
18,652 25,788
------------ --------------
LONG-TERM DEBT........................................................... 45,300 35,700
------------ --------------
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 - 8,916,283 shares in 1998 and 8,980,539
shares in 1997....................................................... 892 898
Additional paid-in capital............................................ 69,618 70,856
Retained earnings (deficit)........................................... (4,819) 2,840
------------ --------------
65,691 74,594
Less treasury stock, at cost (95,000 shares in 1997).................. - (1,520)
------------ ---------------
65,691 73,074
------------ --------------
$ 129,643 $ 134,562
============ ==============
</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,
------------------------------- --------------------------
1998 1997 1998 1997
------------- -------------- ------------- ---------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales ...................... $ 11,479 $ 18,718 $ 42,044 $ 51,538
Natural gas services ................... 905 1,207 2,953 3,374
-------- -------- -------- --------
Total revenues ....................... 12,384 19,925 44,997 54,912
-------- -------- -------- --------
COSTS AND EXPENSES
Lease operations ....................... 3,251 3,917 10,903 11,847
Exploration:
Abandonments and impairments ......... 1,760 28 7,236 750
Seismic and other .................... 823 3,920 2,872 7,451
Natural gas services ................... 806 1,070 2,515 2,849
Depreciation, depletion and amortization 6,881 8,611 24,707 22,561
General and administrative ............. 868 806 3,040 2,767
-------- -------- -------- --------
Total costs and expenses ............. 14,389 18,352 51,273 48,225
-------- -------- -------- --------
Operating income (loss) .............. (2,005) 1,573 (6,276) 6,687
-------- -------- -------- --------
OTHER INCOME (EXPENSE)
Interest expense ....................... (554) (480) (1,539) (1,271)
Other .................................. 134 14 156 109
-------- -------- -------- --------
Total other income (expense) ......... (420) (466) (1,383) (1,162)
-------- -------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES ......... (2,425) 1,107 (7,659) 5,525
INCOME TAX EXPENSE ........................ - - - -
-------- -------- -------- --------
NET INCOME (LOSS) ......................... $ (2,425) $ 1,107 $ (7,659) $ 5,525
======== ======== ======== ========
Net income (loss) per common share:
Basic .................................. $ (.27) $ .12 $ (.86) $ .62
======== ======== ======== ========
Diluted ................................ $ (.27) $ .12 $ (.86) $ .61
======== ======== ======== ========
Weighted average common shares outstanding:
Basic .................................. 8,907 8,888 8,897 8,889
======== ======== ======== ========
Diluted ................................ 8,907 9,094 8,897 9,094
======== ======== ======== ========
</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)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------------
1998 1997
------------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) ............................................ $ (7,659) $ 5,525
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
Depreciation, depletion and amortization ................. 24,707 22,561
Exploration costs ........................................ 7,236 750
Other .................................................... 236 287
Changes in operating working capital:
Accounts receivable ...................................... 5,012 866
Accounts payable ......................................... (1,642) 79
Other .................................................... 856 (760)
-------- --------
Net cash provided by operating activities ........... 28,746 29,308
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment .......................... (38,170) (38,646)
Proceeds from sales of property and equipment ................ 79 157
-------- --------
Net cash used in investing activities ............... (38,091) (38,489)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt ................................. 9,600 9,500
Repurchase of common stock for treasury ...................... - (1,115)
Proceeds from sale of common stock ........................... 7 29
-------- --------
Net cash provided by financing activities ........... 9,607 8,414
-------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS .............. 262 (767)
CASH AND CASH EQUIVALENTS
Beginning of period .......................................... 2,150 2,479
-------- --------
End of period ................................................ $ 2,412 $ 1,712
======== ========
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized ........... $ 1,496 $ 1,235
======== ========
</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, 1998
(UNAUDITED)
1. ORGANIZATION AND PRESENTATION
Clayton Williams Energy, Inc. (the "Company"), a Delaware corporation,
was incorporated in September 1991 for the purpose of consolidating and
continuing certain operations previously conducted by affiliates of Clayton W.
Williams, Jr. ("Mr. Williams"). Concurrent with the completion of the initial
public offering of the Company's common stock on May 26, 1993, these operations
were consolidated, and the Company succeeded to most of the oil and gas
properties, exploration and development operations and the natural gas gathering
and marketing operations of Mr. Williams and his affiliates. The consolidated
financial statements include the accounts of the Company and its subsidiaries.
All significant intercompany transactions and balances associated with the
consolidated operations have been eliminated.
The Company is primarily engaged in oil and gas exploration, development
and production activities in south and east Texas, southeastern New Mexico and
the Texas Gulf Coast. The Company has also initiated exploration activities in
Louisiana and Mississippi.
In the opinion of management, the Company's unaudited consolidated
financial statements as of September 30, 1998 and for the interim periods ended
September 30, 1998 and 1997 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, 1998.
The preparation of 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.
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 ("SEC"). These
consolidated financial statements should be read in conjunction with the audited
consolidated financial statements and notes thereto included in the Company's
1997 Form 10-K.
2. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1998 1997
--------------- ------------
(IN THOUSANDS)
<S> <C> <C>
Secured Bank Credit Facility (matures July 31, 2001)............ $ 45,300 $ 35,700
Other........................................................... - 42
----------- -----------
45,300 35,742
Less current maturities......................................... - 42
----------- -----------
$ 45,300 $ 35,700
=========== ===========
</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. In
July 1998, the banks established a borrowing base of $50 million, leaving $4.7
million available on the Credit Facility at September 30, 1998. The borrowing
base is presently being redetermined and is scheduled to be redetermined in May
1999 and at least semi-annually thereafter; however, either the Company or the
banks may request a borrowing base redetermination at any other time during the
year. Any redetermination will be made at the discretion of the banks. If, at
any time, outstanding advances plus letters of credit exceed the borrowing base,
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 the facility 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.
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 will 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 will bear interest at the LIBOR rate for a fixed period of time elected by
the Company plus a Eurodollar Margin ranging from 1% to 1.75% per annum. At
September 30, 1998, the Company's indebtedness under the Credit Facility
consisted of $42 million of Eurodollar Loans at a rate of 7.4% and $3.3 million
of Base Rate Loans at a rate of 8.6%.
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 which are computed
quarterly and require the Company to maintain minimum levels of working capital,
cash flow and net tangible assets. At September 30, 1998, the Company was not in
compliance with the working capital covenant; however, the banks waived such
non-compliance with respect to the September 30, 1998 computation.
3. CANCELLATION OF TREASURY STOCK
In June 1998, the Company cancelled 95,000 shares of its common stock
held as treasury stock. The cost of the cancelled shares, which totalled
$1,520,000, was reclassified as a reduction in common stock and additional
paid-in capital.
4. EARNINGS PER SHARE
In December 1997, the Company adopted Statement of Financial Accounting
Standards No. 128 "Earnings Per Share" ("SFAS 128"), which changes the method of
computing and disclosing earnings per share for periods ending after December
15, 1997. In accordance with SFAS 128, basic earnings per common share was
computed by dividing net income (loss) by the weighted average number of shares
of common stock outstanding during the period. Diluted earnings per common share
was computed by including the dilutive effect, if any, of outstanding employee
stock options utilizing the treasury stock method. All prior periods have been
restated to give effect to the adoption of SFAS 128, the impact of which was
immaterial. For all periods presented, the differences between basic shares and
diluted shares were attributable to the dilutive effect of employee stock
options.
5. 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, 1998, the Company issued Mr. Williams
20,937
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shares of common stock in lieu of cash compensation aggregating $208,021.
Subsequent to September 30, 1998, the Company issued Mr. Williams an
additional 5,058 shares in lieu of cash compensation aggregating $46,801. The
amounts of such compensation are included in general and administrative
expense in the accompanying consolidated financial statements.
6. FORWARD SALE TRANSACTIONS
The Company accounts for forward sale and put option arrangements as
hedging activities and, accordingly, gains and losses are included in oil and
gas revenues in the period the hedged production is sold. Included in oil and
gas revenues during the nine months ended September 30, 1998 are net gains
totaling $7,228,000 (comprised of gains of $7,381,000, partially offset by
losses of $153,000). The Company did not hedge any of its oil and gas production
during the 1997 period.
In addition, the Company has entered into swap arrangements for 324,000
barrels of oil production for the period from October 1998 through December 1998
at an average price of $19.51 and has hedged 1,030,000 MMBtu of gas production
for the period from October 1998 through December 1998 at an average price of
$2.64.
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, 1998 and 1997 to the extent
net deferred tax assets exceed net deferred tax liabilities.
8. RECENT ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130 "Reporting Comprehensive Income"
("SFAS 130"). SFAS 130 establishes standards for reporting and displaying of
comprehensive income and its components (revenue, expenses, gains and losses) in
a full set of general-purpose financial statements. During the three months and
nine months ended September 30, 1998 and 1997, the Company reported no
differences between comprehensive income and net income.
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 2000 and is not expected to have a
material effect on the Company's financial condition or operations.
9. SUBSEQUENT EVENT
In October 1998, the Company entered into an agreement to purchase
certain oil and gas properties in east Texas for $46.5 million. The Company will
acquire 10% of the purchased properties and will serve as general partner of a
limited partnership which will acquire the remaining 90%. After the limited
partner receives an agreed-upon rate of return, the Company's general
partnership interest will increase from 1% to 35%. The closing is expected to
occur in November 1998, with an effective date of April 1, 1998.
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, 1998 and
results of operations and cash flows for the periods ended September 30, 1998
and 1997. This discussion should be read in conjunction with the Company's Form
10-K for the year ended December 31, 1997 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 has been required
to maintain or increase its level of drilling activity and achieve comparable or
improved results from such activities. Except for its participation in wells
proposed by other operators and wells which must be drilled in order to preserve
its drilling rights, the Company has indefinitely suspended Trend drilling
activities until oil prices improve and stabilize.
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 is devoting a substantial portion of its capital expenditures
to these new areas and is actively seeking and evaluating opportunities to
acquire proven properties. See "LIQUIDITY AND CAPITAL RESOURCES - CAPITAL
EXPENDITURES."
A significant portion of the Company's capital expenditures during the
first nine months of 1998 have been spent on acquisitions of exploratory
acreage, exploratory wells which have not been completed and exploratory wells
which have resulted in dry holes. Accordingly, production from new wells has not
been sufficient to offset the recent declines in oil production attributable to
the suspension of Trend drilling. 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
9
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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.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------------- -----------------------
1998 1997 1998 1997
-------- ------- -------- ------
<S> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (MBbls)............................ 570 820 2,066 2,102
Gas (MMcf)............................. 1,250 1,293 3,671 3,790
MBOE (1)............................... 778 1,036 2,678 2,734
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl)............................ $ 15.32 $ 19.11 $ 16.34 $ 20.00
Gas ($/Mcf)............................ $ 2.35 $ 2.44 $ 2.38 $ 2.52
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses............... $ 4.18 $ 3.78 $ 4.07 $ 4.33
Oil and gas depletion.................. $ 8.59 $ 8.10 $ 8.96 $ 8.02
NET WELLS DRILLED (3):
Exploratory Wells...................... 2.7 2.0 5.2 7.3
Developmental Wells.................... - 7.0 4.4 21.9
</TABLE>
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(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 September 30, 1998 and 1997.
THREE MONTHS ENDED SEPTEMBER 30, 1998 COMPARED TO SEPTEMBER 30, 1997
REVENUES
Oil and gas sales decreased 39% from $18.7 million in 1997 to $11.5
million in 1998 due primarily to a combination of lower oil prices and a 30%
decline in oil production. The Company's average oil price (after giving effect
to a $3.54 per barrel gain on hedging transactions) decreased 20% in 1998 as
compared to 1997. Excluding hedging transactions, the average price per barrel
of oil declined 38% from $19.11 in 1997 to $11.78 in 1998. Low oil prices have
also had a negative impact on the volume of oil produced during the quarter.
Except for its participation in wells proposed by other operators and wells
which must be drilled in order to preserve its drilling rights, the Company has
indefinitely suspended Trend drilling activities until oil prices improve and
stabilize. In addition, the Company initiated a production curtailment strategy
during the second quarter of 1998 by voluntarily reducing the rate of production
on certain of its oil properties in the Trend in an effort to retain the
curtailed production for sale at more favorable prices. This curtailment
strategy was adjusted during the third quarter of 1998 to lessen its impact on
production, resulting in a decrease in curtailed production from 48,000 net
barrels in the second quarter of 1998 to 32,000 net barrels during the third
quarter of 1998. The Company is currently evaluating this curtailment strategy
to determine the extent and duration of future production curtailments. Both the
suspension of Trend drilling and the curtailment of production for an extended
period of time may adversely affect the Company's reported production volumes
and revenues in future periods.
10
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Revenues from natural gas services decreased 21% from $1.2 million in
1997 to $905,000 in 1998 due primarily to a decrease in contract volumes.
COSTS AND EXPENSES
Lease operations expenses decreased 15% from $3.9 million in 1997 to $3.3
million in 1998 due primarily to lower production taxes resulting from a
significant decline in oil prices. Oil and gas production on a BOE basis
decreased 25% during the current quarter, causing an 11% increase in lease
operations expenses on a BOE basis from $3.78 per BOE in 1997 to $4.18 per BOE
in 1998.
Exploration costs decreased 33% from $3.9 million in 1997 to $2.6 million
in 1998 due primarily to lower seismic costs during the current quarter, which
was offset in part by the charge-off of two exploratory dry holes. At September
30, 1998, the Company had capitalized $8.4 million of drilling costs on
exploratory wells which were in varying stages of drilling, completion and
evaluation, and expects to incur additional exploratory drilling costs on these
wells and other wells during the fourth quarter of 1998. See "LIQUIDITY AND
CAPITAL RESOURCES - CAPITAL EXPENDITURES." 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.
DD&A expense decreased 20% from $8.6 million in 1997 to $6.9 million in
1998 due primarily to a 25% decrease in oil and gas production on a BOE basis
during the 1998 quarter, offset in part by a 6% increase in the Company's
average depletion rate per BOE. 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 increase in
the average depletion rate per BOE was attributable primarily to the effects of
lower oil and gas prices on proved reserves, offset largely by upward reserve
revisions reported during the third quarter of 1998 related to improved
production performance on certain Trend wells.
Costs of natural gas services decreased 27% from $1.1 million in 1997 to
$806,000 in 1998 due primarily to a decrease in contract volumes.
INTEREST EXPENSE AND OTHER
Interest expense increased 15% from $480,000 in 1997 to $554,000 in 1998
due primarily to higher average levels of indebtedness on the Credit Facility,
which was substantially offset by an increase in capitalized interest and
slightly lower average interest rates. The average daily principal balance
outstanding on such facility during the third quarter of 1998 was $41.9 million
compared to $26.0 million in 1997. The effective annual interest rate on bank
debt, including bank fees, during the 1998 quarter was 8.2% compared to 8.7% in
1997. Capitalized interest was $242,000 higher during the 1998 quarter due to a
significant increase in unproved acreage since September 30, 1997.
NINE MONTHS ENDED SEPTEMBER 30, 1998 COMPARED TO SEPTEMBER 30, 1997
REVENUES
Oil and gas sales decreased 18% from $51.5 million in 1997 to $42.0
million in 1998 due primarily to lower oil prices. The Company's average oil
price during the current period declined 18% (after giving effect to a $3.26 per
barrel gain on hedging activities). Excluding hedging transactions, the
Company's average price per barrel of oil declined 35% from $20.00 in 1997 to
$13.08 in 1998. Although oil production for the current period decreased 2% as
compared to the 1997 period, several factors related to the current depressed
levels of oil prices had a negative impact on production. Except for its
participation in wells proposed by other operators and wells which must be
drilled in order to preserve its drilling rights, the Company has indefinitely
suspended Trend drilling activities until oil prices improve and stabilize.
During the second quarter of 1998, the Company initiated an oil curtailment
strategy that resulted in a decrease of
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approximately 80,000 net barrels of oil production during the first nine
months of 1998. The Company is currently evaluating this curtailment strategy
to determine the extent and duration of future production curtailments. Both
the suspension of Trend drilling and the curtailment of production for an
extended period of time may adversely affect the Company's reported
production volumes and revenues in future periods.
COSTS AND EXPENSES
Lease operations expenses decreased 8% from $11.8 million in 1997 to
$10.9 million in 1998 due primarily to lower production taxes resulting from a
significant decline in oil prices. Oil and gas production on a BOE basis
decreased 2% during the current period, causing a 6% decrease in lease
operations expenses on a BOE basis from $4.33 per BOE in 1997 to $4.07 per BOE
in 1998.
Exploration costs increased 23% from $8.2 million in 1997 to $10.1
million in 1998 due primarily to the charge-off of five exploratory dry holes
during the 1998 period, which was offset in part by lower seismic costs. At
September 30, 1998, the Company had capitalized $8.4 million of drilling costs
on exploratory wells which were in varying stages of drilling, completion and
evaluation, and expects to incur additional exploratory drilling costs on these
wells and other wells during the fourth quarter of 1998. See "LIQUIDITY AND
CAPITAL RESOURCES - CAPITAL EXPENDITURES." 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.
DD&A expense increased 9% from $22.6 million in 1997 to $24.7 million in
1998 due primarily to a 12% increase in the Company's average depletion rate
attributable to the effects of lower oil and gas prices on estimated quantities
of proved reserves. 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.
INTEREST EXPENSE AND OTHER
Interest expense increased 15% from $1.3 million in 1997 to $1.5 million
in 1998 due primarily to higher average levels of indebtedness on the Credit
Facility, offset in part by an increase in capitalized interest and slightly
lower average interest rates. The average daily principal balance outstanding on
such facility during the first nine months of 1998 was $37.7 million compared to
$21.5 million in 1997. The effective annual interest rate on bank debt,
including bank fees, during the 1998 period was 8.2% compared to 8.9% in 1997.
Capitalized interest was $649,000 higher during the 1998 period due to a
significant increase in unproved acreage since September 30, 1997.
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.
The following discussion sets forth the Company's current plans for
capital expenditures in 1998, and the expected capital resources needed to
finance such plans.
12
<PAGE>
CAPITAL EXPENDITURES
Until oil prices improve and stabilize, the Company has generally
suspended its Trend drilling activities, except for its participation in wells
proposed by other operators and wells which must be drilled in order to preserve
the Company's drilling rights. During the first nine months of 1998, the Company
spent $8.4 million on Trend drilling and leasing activities compared to $33.2
million during the first nine months of 1997.
In 1998, the Company is devoting a substantial portion of its capital
expenditures to its emerging exploration program. Drilling operations are in
progress on a 16,000-foot exploratory gas well to test one of the reef anomalies
identified through a 3-D seismic survey completed in 1997 in connection with its
Cotton Valley Pinnacle Reef play. This well was successfully drilled into a reef
complex and reached a total depth of 16,175 feet. However, due to mechanical
problems, the Company was unable to complete the well and elected to sidetrack
the well at a vertical depth of 14,100 feet and re-drill the remaining 2,000
feet through the reef. The Company has successfully drilled a second well bore
through the reef and plans to begin completion operations before the end of
November 1998. In comparison to the previous estimate of $9.5 million, the
Company now estimates that it will spend a total of approximately $10.6 million
in 1998 on drilling, leasing and seismic activities in this area, of which $5.8
million has been incurred during the first nine months of 1998.
The Company is also exploring for gas reserves in the Glen Rose formation
utilizing its horizontal drilling expertise. The Company has completed one
exploratory well and is currently drilling a second well, both in Walker County,
Texas. During the first nine months of 1998, the Company incurred $8.2 million
on leasing and drilling activities in this area and plans to incur a total of
approximately $9.3 million in 1998.
The Company has conducted three separate 3-D seismic surveys in south
Texas, one in 1997 and two in 1998. Based upon these surveys, the Company has
drilled and completed two wells and has drilled and temporarily abandoned one
well in this area. During the remainder of 1998, the Company plans to drill
three additional wells based on these surveys. During the first nine months of
1998, the Company incurred $3.9 million on leasing, seismic and drilling
activities on these south Texas prospects and plans to incur a total of
approximately $6.4 million on these prospects in 1998.
In addition, the Company incurred $8.0 million during the first nine
months of 1998 on other exploration projects, primarily in east Texas, Louisiana
and Mississippi, where the Company has drilled 4 dry holes in 1998 and is
currently attempting to complete a well in Mississippi and recomplete a well in
Louisiana. The Company plans to incur a total of approximately $10.0 million on
such projects during 1998.
In October 1998, the Company entered into an agreement to purchase
certain oil and gas properties in east Texas for $46.5 million. The Company will
acquire 10% of the purchased properties and will serve as general partner of a
limited partnership which will acquire the remaining 90%. After the limited
partner receives an agreed-upon rate of return, the Company's general
partnership interest will increase from 1% to 35%. The closing is expected to
occur in November 1998, with an effective date of April 1, 1998.
A portion of the activity planned for the remainder of 1998 is
discretionary. This allows the Company to make adjustments to its level of
capital and exploratory expenditures based upon such factors as the availability
of capital resources, product prices and drilling results. Thus, if the
Company's ability or desire to conduct the planned activities is diminished or
enhanced by any of these factors, the Company can modify its expenditures
accordingly. See "CAPITAL RESOURCES."
CAPITAL RESOURCES
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
13
<PAGE>
Company to be the elected borrowing limit. In July 1998, the banks
established a borrowing base of $50 million, leaving $4.7 million available
on the Credit Facility at September 30, 1998. However, subsequent borrowings
have eliminated substantially all of the availability under the Credit
Facility. The Company has requested an increase in the borrowing base, and
the banks are presently evaluating changes to the Company's reserves since
July 1998, which changes relate primarily to (i) increases in proved
developed reserve estimates attributable to certain Trend wells, (ii)
additions to proved undeveloped reserves attributable to the Cotton Valley
Pinnacle Reef well currently being drilled and certain drilling locations in
the Trend, and (iii) purchases of proved reserves. To the extent the banks
increase the borrowing base, the Company intends to use such borrowing
capacity, together with internally generated funds, to finance the remainder
of its 1998 planned capital and exploratory expenditures.
WORKING CAPITAL AND CASH FLOW
During the first nine months of 1998, the Company generated cash flow
from operating activities of $28.7 million, borrowed $9.6 million on the Credit
Facility, and spent $38.2 million on capital expenditures.
The Company's working capital deficit decreased from $6.4 million at
December 31, 1997 to $5.5 million at September 30, 1998. The Company applies
most of its available cash toward the repayment of the Credit Facility. Since
all outstanding indebtedness on the Credit Facility is classified as a
noncurrent liability, the timing of receipts and disbursements can cause
reported working capital to fluctuate. However, working capital increases as
funds are advanced on the Credit Facility to finance the Company's capital
expenditure program.
ADDITIONAL CAPITAL RESOURCES
The Company believes that the funds which will be available under the
Credit Facility upon completion of the current borrowing base redetermination,
combined with operating cash flow, will be adequate to fund the Company's
projected capital and exploratory expenditures during the remainder of 1998.
However, because future cash flows and the availability of borrowings are
subject to a number of variables, such as the level of production from existing
wells, the Company's success in developing and producing new reserves,
prevailing prices of oil and gas, 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.
If funds available under the Credit Facility, combined with operating
cash flow, are not sufficient to fund its non-discretionary capital
expenditures, the Company will be required to seek alternative forms of capital
resources, including the sale of non-strategic 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, there can be no
assurance that any such capital resources will be available to the Company on
terms and conditions which are favorable to the Company's existing shareholders.
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.
INFORMATION SYSTEMS FOR THE YEAR 2000
The Company has reviewed and evaluated its information systems to
determine if its systems accurately process data referencing the year 2000.
Substantially all necessary programming modifications to correct year 2000
referencing in internal accounting and operating systems have been made. Since
the Company's primary information system is covered by a software maintenance
agreement, the Company's cost to implement the Year 2000 conversion was nominal.
However, the Company has not completed its evaluation of systems used by major
purchasers, vendors, suppliers and financial institutions to determine the
effect, if any, that non-compliance of such systems would have on the operations
of the Company. The Company expects to have all third-party evaluations
completed by early 1999.
14
<PAGE>
HEDGING TRANSACTIONS
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more predictable
cash flow, as well as to reduce 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 and
collars, 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 allows for the future physical
delivery of the hedged products.
The Company has entered into swap arrangements for 324,000 barrels of oil
production for the period from October 1998 through December 1998 at an average
price of $19.51, and has hedged 1,030,000 MMBtu of gas production for the period
from October 1998 through December 1998 at an average price of $2.64.
15
<PAGE>
PART II. OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- ------------------------
27 Financial Data Schedule
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended September
30, 1998.
16
<PAGE>
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 11, 1998 By: /s/ L. Paul Latham
------------------------------
L. Paul Latham
Executive Vice President and
Chief Operating Officer
Date: November 11, 1998 By: /s/ Mel G. Riggs
-------------------------------
Mel G. Riggs
Senior Vice President and Chief
Financial Officer
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
REGISTRANT'S CONDENSED CONSOLIDATED FINANCIAL STATEMENTS FOR THE QUARTER ENDED
SEPTEMBER 30, 1998 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
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<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<CASH> 2,412
<SECURITIES> 0
<RECEIVABLES> 8,484
<ALLOWANCES> 0
<INVENTORY> 1,562
<CURRENT-ASSETS> 13,140
<PP&E> 456,524
<DEPRECIATION> 340,077
<TOTAL-ASSETS> 129,643
<CURRENT-LIABILITIES> 18,652
<BONDS> 45,300
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<COMMON> 892
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<TOTAL-LIABILITY-AND-EQUITY> 129,643
<SALES> 42,044
<TOTAL-REVENUES> 44,997
<CGS> 10,903
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<INTEREST-EXPENSE> 1,539
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