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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, 2000
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, 2000.....9,251,861.
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CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION
<S> <C> <C>
ITEM 1. FINANCIAL STATEMENTS PAGE
Consolidated Balance Sheets as of September 30, 2000 and December 31, 1999.................. 3
Consolidated Statements of Operations for the three months and nine months ended
September 30, 2000 and 1999............................................................... 4
Consolidated Statements of Cash Flows for the nine months ended September 30, 2000 and 1999. 5
Notes to Consolidated Financial Statements.................................................. 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS....... 10
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS.................................. 16
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......................................... 18
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................................................ 18
</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,
2000 1999
--------------- ---------------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents......................................... $ 2,640 $ 1,634
Accounts receivable:
Trade, net.................................................... 3,456 2,661
Affiliates.................................................... 3,368 729
Oil and gas sales............................................. 19,937 9,846
Inventory......................................................... 1,228 717
Deferred income taxes............................................. 1,042 -
Other............................................................. 1,678 313
--------------- ---------------
33,349 15,900
--------------- ---------------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method................. 477,193 436,831
Natural gas gathering and processing systems...................... 13,105 9,810
Other............................................................. 10,449 10,350
--------------- ---------------
500,747 456,991
Less accumulated depreciation, depletion and amortization......... (381,330) (363,985)
--------------- ---------------
Property and equipment, net................................... 119,417 93,006
--------------- ---------------
OTHER ASSETS........................................................... 255 260
--------------- ---------------
$ 153,021 $ 109,166
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES Accounts payable:
Trade......................................................... $ 24,766 $ 13,648
Affiliates.................................................... 207 310
Oil and gas sales............................................. 13,152 7,785
Accrued liabilities and other..................................... 2,960 806
--------------- ---------------
41,085 22,549
--------------- ---------------
LONG-TERM DEBT......................................................... 27,000 30,500
--------------- ---------------
DEFERRED INCOME TAXES.................................................. 1,420 -
--------------- ---------------
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 - 30,000,000
shares; issued - 9,249,106 shares in 2000 and 9,167,779
shares in 1999................................................... 925 917
Additional paid-in capital........................................ 72,402 70,690
Retained earnings (deficit)....................................... 10,189 (15,490)
--------------- ---------------
83,516 56,117
--------------- ---------------
$ 153,021 $ 109,166
=============== ===============
</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,
----------------------------- -----------------------------
2000 1999 2000 1999
------------- ------------- ------------- --------------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales............................. $ 29,848 $ 12,675 $ 74,397 $ 30,105
Natural gas services.......................... 2,238 1,061 4,597 2,737
------------- ------------- ------------- --------------
Total revenues............................ 32,086 13,736 78,994 32,842
------------- ------------- ------------- --------------
COSTS AND EXPENSES
Lease operations.............................. 5,055 2,898 13,224 8,286
Exploration:
Abandonments and impairments.............. 1,559 1,237 4,826 2,131
Seismic and other......................... 1,808 451 3,851 828
Natural gas services.......................... 1,925 857 3,952 2,313
Depreciation, depletion and amortization...... 8,051 5,081 20,000 15,921
General and administrative.................... 1,087 703 3,040 2,574
Stock-based employee compensation............. 2,221 - 2,221 -
------------- ------------- ------------- --------------
Total costs and expenses.................. 21,706 11,227 51,114 32,053
------------- ------------- ------------- --------------
Operating income.......................... 10,380 2,509 27,880 789
------------- ------------- ------------- --------------
OTHER INCOME (EXPENSE)
Interest expense.............................. (560) (685) (1,815) (2,162)
Gain on sales of property and equipment....... - 21 1,018 10,614
Other......................................... 116 51 181 418
------------- ------------- ------------- --------------
Total other income (expense).............. (444) (613) (616) 8,870
------------- ------------- ------------- --------------
INCOME BEFORE INCOME TAXES......................... 9,936 1,896 27,264 9,659
INCOME TAX EXPENSE................................. 1,585 - 1,585 -
------------- ------------- ------------- --------------
NET INCOME......................................... $ 8,351 $ 1,896 $ 25,679 $ 9,659
============= ============= ============= ==============
Net income per common share:
Basic......................................... $ .90 $ .21 $ 2.79 $ 1.08
============= ============= ============= ==============
Diluted....................................... $ .87 $ .20 $ 2.70 $ 1.05
============= ============= ============= ==============
Weighted average common shares outstanding:
Basic......................................... 9,228 8,986 9,197 8,971
============= ============= ============= ==============
Diluted....................................... 9,599 9,288 9,526 9,171
============= ============= ============= ==============
</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,
------------------------------
2000 1999
------------- -------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.............................................................. $ 25,679 $ 9,659
Adjustments to reconcile net income to cash provided by
operating activities:
Depreciation, depletion and amortization............................ 20,000 15,921
Exploration costs................................................... 4,826 2,131
Gain on sales of property and equipment............................. (1,018) (10,614)
Deferred income taxes............................................... 1,527 -
Stock-based employee compensation................................... 2,221 -
Other............................................................... 293 204
Changes in operating working capital:
Accounts receivable................................................. (13,525) (615)
Accounts payable.................................................... 12,247 (1,574)
Other............................................................... (1,940) (115)
------------- -------------
Net cash provided by operating activities...................... 50,310 14,997
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment..................................... (47,148) (13,732)
Proceeds from sales of property and equipment........................... 1,064 18,486
Other................................................................... 2 -
------------- -------------
Net cash provided by (used in) investing activities............ (46,082) 4,754
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of long-term debt............................................ (3,500) (15,900)
Proceeds from sale of common stock...................................... 278 72
------------- -------------
Net cash used in financing activities.......................... (3,222) (15,828)
------------- -------------
NET INCREASE IN CASH AND CASH EQUIVALENTS.................................... 1,006 3,923
CASH AND CASH EQUIVALENTS
Beginning of period..................................................... 1,634 1,424
------------- -------------
End of period........................................................... $ 2,640 $ 5,347
============= =============
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized...................... $ 1,957 $ 2,264
============= =============
</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, 2000
(UNAUDITED)
1. NATURE OF OPERATIONS
Clayton Williams Energy, Inc. (a Delaware corporation) 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 Texas, Louisiana and New Mexico.
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, 2000 and for the interim periods ended
September 30, 2000 and 1999 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, 2000.
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
1999 Form 10-K.
3. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
--------------- ---------------
(IN THOUSANDS)
<S> <C> <C>
Secured Bank Credit Facility (matures July 31, 2002).............. $ 27,000 $ 30,500
=============== ===============
</TABLE>
6
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The Company's secured bank 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 in May and November, 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.
Effective July 1, 2000, the borrowing base established by the banks
was increased from $48 million to $50 million, with no monthly commitment
reductions.
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. Prior to July 1, 2000,
Eurodollar Loans bore interest at the LIBOR rate plus a Eurodollar Margin
ranging from 1.75% to 2.5% per annum. Effective July 1, 2000, the Eurodollar
Margins were reduced by .5% and presently range from 1.25% to 2.0%. At September
30, 2000, the Company's indebtedness under the credit facility consisted of $27
million of Eurodollar Loans at a rate of 8.4%.
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, 2002.
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 and non-financial covenants at September 30, 2000.
4. STOCK COMPENSATION PLANS
In May 1995, the Company's Board of Directors adopted the Executive
Incentive Stock Compensation Plan, permitting the Company, at its discretion, 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, 2000, the Company
issued 9,751 shares of common stock to one officer in lieu of cash compensation
aggregating $172,913, which is included in general and administrative expense in
the accompanying consolidated financial statements. Subsequent to September 30,
2000, the Company issued an additional 1,174 shares to the same officer in lieu
of cash compensation aggregating $38,720.
In March 2000, the Financial Accounting Standards Board issued
Interpretation No. 44 ("FIN 44") to Accounting Principles Board Opinion No. 25
"Accounting for Stock Issued to Employees" ("APB 25") which became effective
July 1, 2000. FIN 44 requires a change in the classification of 233,141 stock
options repriced by the Company in April 1999 from fixed stock options to
variable stock options. Therefore, the Company is now required to recognize
compensation expense on the repriced options to the extent that the quoted
market value of the Company's common stock at the end of each period exceeds the
amended option price ($5.50 per share), except that options vested at the
effective date of FIN 44 must recognize compensation expense only to the extent
that the quoted market value exceeds the market value on the effective date of
FIN 44 ($31.94 per share). The Company's closing market price at September 30,
2000 was $40.50. Accordingly, the Company made a non-cash provision for
stock-based employee compensation of $2,221,000 for the quarter ended September
30, 2000. As the repriced options are exercised, the cumulative amount of
accrued compensation expense will be credited to additional
7
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paid-in capital. Since this provision is based on changes in the quoted market
value of the Company's common stock, the Company's future results of operations
may be subject to significant volatility. Assuming the Company's quoted market
value at December 31, 2000 will be equal to $31.00 per share (the closing price
on November 9, 2000), the cumulative provision for stock-based employee
compensation will be reduced by approximately $1.1 million during the fourth
quarter of 2000.
5. HEDGING 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, 2000 and
1999 are losses totaling $962,000 and $309,000, respectively.
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 in Lea County, New Mexico for $12.5
million and recorded a gain of $8.4 million.
In April 2000, the Company sold 50% of its interest in a prospect in
Duval County, Texas for $1 million. Since the cost of this prospect had been
fully amortized in prior periods, the Company recognized a gain during the
second quarter of 2000 equal to the amount of proceeds.
7. INCOME TAXES
Prior to September 30, 2000, the Company's deferred tax assets exceeded
its deferred tax liabilities due primarily to the existence of tax loss
carryforwards available to offset future taxable income. Due to the uncertainty
of realizing the related future benefits from such tax loss carryforwards,
valuation allowances were recorded at each balance sheet date to the extent net
deferred tax assets exceeded net deferred tax liabilities.
During the third quarter of 2000, the Company's pre-tax income was
sufficient to cause deferred tax liabilities to exceed deferred tax assets.
Based upon current commodity prices and production volumes, as well as the
availability of tax planning strategies (such as elective capitalization of
intangible drilling costs), the Company presently believes that it is more
likely than not that the Company will be able to utilize its tax loss
carryforwards before they expire (beginning in 2008). Accordingly, the Company
reversed the valuation allowance provided at December 31, 1999 during the
nine-month period ended September 30, 2000.
The Company's effective income tax rate was different than the statutory
federal income tax rate for the following reasons:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, 2000
-------------------
(IN THOUSANDS)
<S> <C>
Income tax expense at statutory rate of 35%......................... $ 9,542
Change in valuation allowance....................................... (7,149)
Tax depletion in excess of basis.................................... (912)
Revision of previous tax estimates.................................. 114
Other............................................................... (10)
-------------------
Income tax expense................................................ $ 1,585
===================
Current............................................................. $ 58
Deferred............................................................ 1,527
-------------------
Income tax expense................................................ $ 1,585
===================
</TABLE>
8
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The Company derives an income tax benefit when employees and directors
exercise options granted under the Company's stock compensation plans (see Note
4). Employee stock options that are classified as fixed stock options under APB
25 do not result in a charge against book income when the option price is equal
to or greater than the market price at date of grant. Therefore, any tax benefit
from the exercise of fixed stock options results in a permanent difference,
which is recorded to additional paid-in capital when the tax benefit is
realized. At December 31, 1999, $585,000 of tax benefits related to the exercise
of fixed stock options was fully reserved by a valuation allowance. During the
current period, the valuation allowance was reversed, and additional tax
benefits totaling $564,000 were realized. Accordingly, the Company credited
additional paid-in capital during the nine-month period ended September 30, 2000
for $1,149,000 related to the exercise of employee stock options.
Deferred tax assets and liabilities are the result of temporary
differences between the financial statement carrying values and the tax bases of
assets and liabilities. The Company's net deferred tax liabilities at September
30, 2000 are recorded as a current asset of $1,042,000 and a non-current
liability of $1,420,000. Significant components of net deferred tax liabilities
at September 30, 2000 and December 31, 1999 are as follows:
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
----------------- -----------------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax assets:
Tax loss carryforwards................................. $ 11,861 $ 12,961
Accrued stock-based compensation....................... 777 -
Other.................................................. 945 956
----------------- -----------------
13,583 13,917
----------------- -----------------
Deferred tax liabilities:
Property and equipment................................. (13,961) (6,183)
----------------- -----------------
Valuation allowance........................................ - (7,734)
----------------- -----------------
Net deferred tax assets (liabilities)...................... $ (378) $ -
================= =================
</TABLE>
8. 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. The Company is currently investigating the effect that SFAS
133 will have on its financial condition and results of operations upon its
adoption effective January 1, 2001. Based on current product prices, the Company
presently estimates that the mark-to-market adjustment at January 1, 2001 with
respect to its existing derivative instruments will result in a liability of $1
million or less, and that a significant portion of the charge will be recorded
to accumulated other comprehensive income.
9. STOCK REPURCHASE PROGRAM
In July 2000, the Company's Board of Directors authorized the expenditure
of up to $2 million for the repurchase of shares of the Company's common stock
on the open market at times and prices deemed appropriate by the Company's
management. This authorization expires in July 2002. To date, the Company has
not repurchased any shares in connection with this authorization.
9
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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, 2000 and
results of operations and cash flows for the periods ended September 30, 2000
and 1999. This discussion should be read in conjunction with the Company's Form
10-K for the year ended December 31, 1999 and the consolidated financial
statements and notes thereto included in this Form 10-Q.
OVERVIEW
A significant portion of the Company's proved oil and gas reserves are
concentrated 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 needs to maintain
or increase its level of drilling activity and achieve comparable or improved
results from such activities.
To reduce its dependence on Trend drilling for future production and
reserve growth, the Company is actively involved in several exploratory
projects, including the Company's Cotton Valley Pinnacle Reef exploratory
project, which targets deep gas structures in the vicinity of its core
properties in east central Texas, as well as other exploratory projects in south
Texas, Louisiana and Mississippi. During the nine months ended September 30,
2000, the Company spent $26.8 million on drilling, leasing, and seismic
activities on exploratory projects and plans to spend an additional $23.9
million in these areas during the fourth quarter of 2000. This accounts for
approximately 60% of the Company's projected capital and exploratory
expenditures for the year 2000. Although exploration activities generally
involve a higher degree of risk than developmental projects, the Company
believes that the potential reserve discoveries justify the associated risks,
particularly during a period of favorable product prices.
With oil prices hovering near record high levels, the Company has
accelerated its efforts to further exploit the developed portion of its Trend
acreage by drilling new horizontal wells in the areas that warrant development
on an increased density basis and by conducting secondary water frac operations
on existing wells. The Company presently plans to spend approximately $23.5
million in the Trend during 2000, of which $17.1 million was incurred at
September 30, 2000.
The Company follows the successful efforts method of accounting for its
oil and gas properties, whereby costs of productive wells, developmental dry
holes and productive leases are capitalized and amortized using the
unit-of-production method based on estimated proved reserves. Costs of unproved
properties are initially capitalized. Those properties with significant
acquisition costs are periodically
10
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assessed and any impairment in value is charged to expense. The amount of
impairment recognized on unproved properties which are not individually
significant is determined by amortizing the costs of such properties within
appropriate groups based on the Company's historical experience, acquisition
dates and average lease terms. Exploration costs, including geological and
geophysical expenses and delay rentals, are charged to expense as incurred.
Exploratory drilling costs, including the cost of stratigraphic test wells, are
initially capitalized but charged to expense if and when the well is determined
to be unsuccessful.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------------------- ---------------------------
2000 1999 2000 1999
------------- ------------ -------------- ----------
<S> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (MBbls)........................ 621 449 1,797 1,398
Gas (MMcf)......................... 2,458 1,158 5,980 3,268
MBOE (1)........................... 1,031 642 2,794 1,943
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl)........................ $ 30.65 $ 20.23 $ 28.96 $ 15.67
Gas ($/Mcf)........................ $ 4.33 $ 2.88 $ 3.61 $ 2.33
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses........... $ 4.90 $ 4.51 $ 4.73 $ 4.26
Oil and gas depletion.............. $ 7.55 $ 7.51 $ 6.89 $ 7.90
NET WELLS DRILLED (3):
Exploratory Wells.................. 2.1 .6 4.2 2.1
Developmental Wells................ 6.6 - 29.3 -
</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, 2000 COMPARED TO SEPTEMBER 30, 1999
REVENUES
Oil and gas sales increased 135% from $12.7 million in 1999 to $29.8
million in 2000 due primarily to significant increases in oil and gas prices,
combined with increases in both oil and gas production. The Company's average
price per barrel of oil increased 52% while average gas prices increased 50%.
Gas production increased 112% due primarily to an increase in production from
the Cotton Valley Pinnacle Reef area. Oil production increased 38% due primarily
to added production from the Company's horizontal drilling and water frac
programs in the Trend and, to a lesser extent, production from the Company's
recent developmental drilling program in Eddy County, New Mexico.
To date, the Company has drilled five wells in the Cotton Valley Pinnacle
Reef area. All of these wells, excluding the J.C. Fazzino Unit #1, the Company's
initial discovery well, have been drilled under a vendor financing arrangement.
During the current quarter, combined gas production from the first three wells,
the Fazzino #1, the Fazzino #2 and the Varisco Estate #1, averaged 32.4 MMcf per
day (16.3 MMcf per day to the Company's interest, net of royalties and vendor
financing arrangements). Since the end of the quarter, these same wells have
averaged 25.3 MMcf per day (12.6 MMcf to the Company's interest).
11
<PAGE>
The Company is also attempting to complete the McGrew #1 in multiple
zones within the target reef, and expects to finalize its completion efforts in
early December. In addition, the Company has recently completed the Muse #1 in
the Cotton Valley (Gilmer) Limestone formation, and may in the future, attempt
completion in a shallower formation.
In October 2000, the Company began drilling the Lee Fazzino #1, a 17,000
foot reef test offsetting the Fazzino #2. The Company owns a 100% working
interest in the Lee Fazzino #1, and is drilling the well, at the Company's
option, without vendor financing arrangements.
Significant uncertainties exist with respect to any estimate of future
production to be derived from these wells due to the limited production history
available at this time. Accordingly, the Company cannot predict the effects of
such production on future revenues and results of operations.
COSTS AND EXPENSES
Lease operations expenses increased 76% from $2.9 million in 1999 to $5.1
million in 2000, while oil and gas production on a BOE basis increased 61%,
resulting in a 9% increase in production costs on a BOE basis from $4.51 in 1999
to $4.90 in 2000. Substantially all of the increase in production costs on a BOE
basis was attributable to the effects of higher oil and gas prices on production
taxes.
Exploration costs doubled from $1.7 million in 1999 to $3.4 million in
2000 due primarily to seismic costs in 2000 attributable to exploratory
prospects being generated in Louisiana and an additional 3-D seismic project in
the Cotton Valley Pinnacle Reef area. 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 increased 59% from $5.1
million in 1999 to $8.1 million in 2000 due primarily to a 61% increase in oil
and gas production on a BOE basis. 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 average
depletion rate per BOE increased from $7.51 in 1999 to $7.55 in 2000.
General and administrative expenses increased 56% from $703,000 in 1999
to $1.1 million in 2000 due primarily to higher personnel costs during the
current period attributable to increased levels of drilling and operating
activities. Low product prices caused the Company to curtail its operations in
early 1999 and implement cost reduction measures consisting primarily of
personnel layoffs and salary reductions. As prices improved in late 1999, the
Company resumed drilling and operating activities and reversed many of the
temporary measures.
A provision for stock-based employee compensation of $2.2 million was
made during the current period pursuant to the requirements of Financial
Accounting Standards Board Interpretation No. 44, which became effective July 1,
2000 (see Note 4 to the accompanying consolidated financial statements). No
corresponding provision was required during the 1999 period. Since the amount of
this non-cash provision is based on the quoted market value of the Company's
common stock, the Company's future results of operations may be subject to
significant volatility.
INTEREST EXPENSE AND OTHER
Interest expense decreased 18% from $685,000 in 1999 to $560,000 in 2000
due primarily to lower average levels of indebtedness on the secured bank credit
facility, offset in part by higher interest rates. The average daily principal
balance outstanding on the credit facility during the current quarter was $30.4
million compared to $39.7 million in the 1999 period. The effective annual
interest rate on bank debt, including bank fees, during the current quarter was
9% compared to 8.2% in the 1999 period.
12
<PAGE>
NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO SEPTEMBER 30, 1999
REVENUES
Oil and gas sales increased 147% from $30.1 million in 1999 to $74.4
million in 2000 due primarily to significant increases in oil and gas prices,
combined with increases in both oil and gas production. The Company's average
price per barrel of oil increased 85% while average gas prices increased 55%.
Oil production increased 29% due primarily to added production from the
Company's horizontal drilling and water frac programs in the Trend. Gas
production increased 83% due primarily to an increase in production from the
Cotton Valley Pinnacle Reef area.
To date, the Company has drilled five wells in the Cotton Valley Pinnacle
Reef area. All of these wells, excluding the J.C. Fazzino Unit #1, the Company's
initial discovery well, have been drilled under a vendor financing arrangement.
During the current period, combined gas production from the first three wells,
the Fazzino #1, the Fazzino #2 and the Varisco Estate #1, averaged 26.9 MMcf per
day (12.7 MMcf per day to the Company's interest, net of royalties and vendor
financing agreements). Since the end of the quarter, these same wells have
averaged 25.3 MMcf per day (12.6 MMcf to the Company's interest).
The Company is also attempting to complete the McGrew #1 in multiple
zones within the target reef, and expects to finalize its completion efforts in
early December. In addition, the Company has recently completed the Muse #1 in
the Cotton Valley (Gilmer) Limestone formation, and may in the future, attempt
completion in a shallower formation.
In October 2000, the Company began drilling the Lee Fazzino #1, a 17,000
foot reef test offsetting the Fazzino #2. The Company owns a 100% working
interest in the Lee Fazzino #1, and is drilling the well, at the Company's
option, without vendor financing arrangements.
Significant uncertainties exist with respect to any estimate of future
production to be derived from these wells due to the limited production history
available at this time. Accordingly, the Company cannot predict the effects of
such production on future revenues and results of operations.
COSTS AND EXPENSES
Lease operations expenses increased 59% from $8.3 million in 1999 to
$13.2 million in 2000, while oil and gas production on a BOE basis increased
44%, resulting in a 11% increase in production costs on a BOE basis from $4.26
in 1999 to $4.73 in 2000. Substantially all of the increase in production costs
on a BOE basis was attributable to the effects of higher oil and gas prices on
production taxes.
Exploration costs increased 190% from $3 million in 1999 to $8.7 million
in 2000 due primarily to the charge off during 2000 of $2.5 million of unproved
property impairments, $2.3 million of dry hole costs and $3.7 million of seismic
costs, as compared to approximately $1.4 million of impairments, $761,000 of dry
hole costs and $625,000 of seismic costs during the nine months ended September
30, 1999. Most of the unproved property impairments in 2000 relate to acreage in
the Glen Rose area of Texas and, to a lesser extent, acreage in a prospect in
Mississippi. Dry hole costs during the current period relate primarily to three
non-operated wells drilled in Duval and Robertson Counties, Texas, and in
Mississippi. Substantially all of the seismic costs in 2000 are attributable to
exploratory prospects being generated in Louisiana and an additional 3-D seismic
project in the Cotton Valley Pinnacle Reef area. 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 increased 26% from $15.9
million in 1999 to $20 million in 2000 due primarily to a 44% increase in oil
and gas production on a BOE basis, offset in part by a 13% decrease in the
average depletion rate. Under the successful efforts method of accounting, costs
of oil
13
<PAGE>
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 $7.90 in 1999 to $6.89 in 2000 was primarily due to higher reserve
estimates attributable to improved product prices.
General and administrative expenses increased 15% from $2.6 million in
1999 to $3 million in 2000 due primarily to higher personnel costs during the
current period attributable to increased levels of drilling and operating
activities. Low product prices caused the Company to curtail its operations in
early 1999 and implement cost reduction measures consisting primarily of
personnel layoffs and salary reduction. As prices improved in late 1999, the
Company resumed drilling and operating activities and reversed many of the
temporary measures.
A provision for stock-based employee compensation of $2.2 million was
made during the current period pursuant to the requirements of Financial
Accounting Standards Board Interpretation No. 44, which became effective July 1,
2000 (see Note 4 to the accompanying consolidated financial statements). No
corresponding provision was required during the 1999 period. Since the amount of
this non-cash provision is based on the quoted market value of the Company's
common stock, the Company's future results of operations may be subject to
significant volatility.
INTEREST EXPENSE AND OTHER
Interest expense decreased 18% from $2.2 million in 1999 to $1.8 million
in 2000 due primarily to lower average levels of indebtedness on the secured
bank credit facility, offset in part by higher interest rates and lower
capitalized interest. The average daily principal balance outstanding on the
credit facility during the 2000 period was $30.8 million compared to $44.3
million in the 1999 period. The effective annual interest rate on bank debt,
including bank fees, during the 2000 period was 9.1% compared to 7.8% in the
1999 period. Capitalized interest during the 2000 period was $302,000 compared
to $447,000 in 1999.
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 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. In
April 2000, the Company sold 50% of its interest in a prospect in Duval County,
Texas for $1 million, resulting in a gain of $1 million.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
The Company's primary financial resource is its oil and gas reserves. In
accordance with the terms of the secured bank 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 2000, and the expected capital resources needed to
finance such plans.
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<PAGE>
CAPITAL EXPENDITURES
During the third quarter of 2000, the Company made significant increases
in its planned capital and exploratory expenditures for the remainder of 2000.
Based on the Company's expectations for continued favorable product prices and
based on the availability of capital resources being generated through operating
activities, the Company has accelerated the timing of certain exploratory and
developmental activities into the fourth quarter of 2000.
The Company presently plans to spend $86 million on exploration and
development activities during 2000, of which $54.4 million has been incurred
through September 30, 2000. The year 2000 estimates include $23.5 million in the
Trend, $23.9 million in the Cotton Valley Pinnacle Reef area, $17.2 million on
various exploratory prospects in Louisiana, $10.1 million in New Mexico, and
$11.3 million on other projects, most of which are exploratory.
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 Company to be the elected
borrowing limit. At September 30, 2000, the borrowing base was $50 million and
the outstanding advances were $27 million. The borrowing base is subject to
redetermination at any time, but at least semi-annually, and is made at the
discretion of the banks. If 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.
WORKING CAPITAL AND CASH FLOW
During the nine months of 2000, the Company generated cash flow from
operating activities of $50.3 million, repaid $3.5 million on the credit
facility and spent $47 million on capital expenditures.
The Company's working capital deficit increased from $6.6 million at
December 31, 1999 to $7.7 million at September 30, 2000 due primarily to a $2.2
million provision during the current quarter for stock-based employee
compensation (see Note 4 to the accompanying consolidated financial statements),
which is classified as a current liability at September 30, 2000. Otherwise, the
Company's working capital deficit generally is a function of its cash management
process. The Company applies most of its available cash toward the repayment of
the credit facility, which is classified as a non-current liability. As advances
are made on the credit facility to pay current liabilities, the Company's
working capital increases. Therefore, the timing of receipts and disbursements
can cause reported working capital to fluctuate.
The Company believes that the funds available under the credit facility
and cash provided by operations will be adequate to fund the Company's
operations and projected capital and exploratory expenditures during 2000.
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>
INFORMATION SYSTEMS FOR THE YEAR 2000
The Company has experienced no computer systems or equipment failures
related to the arrival of the Year 2000. All systems and equipment have
continued to be operational, and the Company has no reason to believe that any
of its systems and equipment are not Year 2000 compliant. Furthermore, the
Company is not aware of any Year 2000 compliance problems of purchasers,
vendors, contractors and other third parties which have adversely affected, or
which may in the future adversely affect, the Company's ability to conduct
business with such third parties. The costs to implement the Year 2000 Plan were
nominal since the primary area for remediation involved software covered by a
maintenance agreement. The Company believes that its Year 2000 plan has been
successfully completed and, except for routine monitoring of its computer
systems and equipment, does not plan to take any further action in regards to
Year 2000 issues.
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, 2000, a $1 change in the price per Bbl of
oil and a $.10 change in the price per Mcf of gas would result in an aggregate
change in annual gross revenues of approximately $3.2 million.
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 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
permits the future physical delivery of the hedged products.
Except for a floor of $10.00 per barrel on 800,000 barrels of oil
production from January 1999 through June 1999, the Company did not have any
significant hedging arrangements in place for 1999. However, in January 2000,
the Company entered into swap arrangements covering 1,830,000 MMBtu of its gas
production from February 2000 through May 2000 at an average price of $2.26 per
MMBtu. This
16
<PAGE>
position was subsequently terminated, and an aggregate loss of approximately
$800,000 was recorded during the nine months ended September 30, 2000.
In February 2000, the Company entered into swap arrangements covering
53,000 barrels of its oil production from October 2000 through December 2000 and
from April 2001 through October 2001 at an average price of $21.69 per barrel
(ranging from a high of $23.71 per barrel in October 2000 to a low of $20.03 in
October 2001), and entered into a collar arrangement covering 17,000 barrels of
its oil production from January 2001 through March 2001 at an average floor
price of $20.66 per barrel and an average ceiling price of $23.81 per barrel.
In September 2000, the Company also entered into swap arrangements
covering 913,000 barrels of its oil production from October 2000 through
December 2001 (ranging from a high of $33.84 per barrel in October 2000 to a low
of $26.92 in December 2001). This position was subsequently terminated and an
aggregate loss of approximately $237,000 will be recorded during the periods
that correlate to the hedged production months.
INTEREST RATES
All of the Company's outstanding indebtedness at September 30, 2000 is
subject to market rates of interest as determined from time to time by the banks
pursuant to the secured bank 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, 2000 of $27 million, a change in interest rates of
25 basis points would affect annual interest payments by approximately $68,000.
17
<PAGE>
PART II. OTHER INFORMATION
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On September 20, the Company held a special meeting of the stockholders to
consider two proposals:
(1) to amend the Certificate of Incorporation of the Company to
increase the number of authorized shares of Common Stock of the
Company from 15 million to 30 million; and
(2) to amend the Company's 1993 Stock Compensation Plan to increase
the number of shares of Common Stock of the Company authorized
and reserved for issuances under the Plan from 898,200 to
1,798,200.
The number of shares of Common Stock represented in person or by proxy and
entitled to vote at the meeting was 6,729,658 shares. The tabulation of
votes was as follows:
<TABLE>
<CAPTION>
PROPOSAL FOR AGAINST ABSTAIN
------------- ----------- ----------- ------------
<S> <C> <C> <C>
No. 1 6,643,212 85,882 564
No. 2 5,079,986 1,553,208 96,464
</TABLE>
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------------ -------------------------------------------------------------
<S> <C>
3.1 Certificate of Amendment of Second Restated Certificate of
Incorporation of Clayton Williams Energy, Inc.
10.1 Amendment to Consolidation Agreement dated August 7, 2000
among Clayton Williams Energy, Inc., Warrior Gas Co.,
Clayton W. Williams, Jr. and the Williams Companies
10.2* Third Amendment to 1993 Stock Compensation Plan, filed as an
exhibit to the Form S-8 Registration Statement No. 333-47232
10.3* Fourth Amendment to 1993 Stock Compensation Plan,
filed as an exhibit to the Form S-8 Registration
Statement No. 333-47232
27 Financial Data Schedule
</TABLE>
----------------------
* Incorporated by reference to the filing indicated.
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended September
30, 2000.
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<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 14, 2000 By: /s/ L. Paul Latham
-----------------------------------------
L. Paul Latham
Executive Vice President and Chief
Operating Officer
Date: November 14, 2000 By: /s/ Mel G. Riggs
-----------------------------------------
Mel G. Riggs
Senior Vice President and Chief Financial
Officer
