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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
/X/ Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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.
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(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
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(Former name, former address and former fiscal year, if changed since last
report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
YES /X/ NO / /
NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF AUGUST 8, 2000.....9,218,281.
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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 June 30, 2000
and December 31, 1999..................................................................... 3
Consolidated Statements of Operations for the three months and six months
ended June 30, 2000 and 1999.............................................................. 4
Consolidated Statements of Cash Flows for the six months
ended June 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.................................. 15
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................................................ 17
</TABLE>
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2
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
--------------- ---------------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents......................................... $ 3,458 $ 1,634
Accounts receivable:
Trade, net.................................................... 2,145 2,661
Affiliates.................................................... 1,256 729
Oil and gas sales............................................. 16,391 9,846
Inventory......................................................... 1,028 717
Other............................................................. 865 313
--------------- ---------------
25,143 15,900
--------------- ---------------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method................. 456,957 436,831
Natural gas gathering and processing systems...................... 12,772 9,810
Other............................................................. 10,408 10,350
--------------- ---------------
480,137 456,991
Less accumulated depreciation, depletion and amortization......... (373,305) (363,985)
--------------- ---------------
Property and equipment, net................................... 106,832 93,006
--------------- ---------------
OTHER ASSETS........................................................... 255 260
--------------- ---------------
$ 132,230 $ 109,166
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade......................................................... $ 15,753 $ 13,648
Affiliates.................................................... 262 310
Oil and gas sales............................................. 10,901 7,785
Accrued liabilities and other..................................... 668 806
--------------- ---------------
27,584 22,549
--------------- ---------------
LONG-TERM DEBT......................................................... 31,000 30,500
--------------- ---------------
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 - 9,211,756 shares in 2000 and 9,167,779
shares in 1999................................................... 921 917
Additional paid-in capital........................................ 70,887 70,690
Retained earnings (deficit)....................................... 1,838 (15,490)
--------------- ---------------
73,646 56,117
--------------- ---------------
$ 132,230 $ 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 SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------- -----------------------------
2000 1999 2000 1999
------------- ------------- ------------- --------------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales............................. $ 25,447 $ 9,909 $ 44,549 $ 17,430
Natural gas services.......................... 1,240 871 2,359 1,676
------------- ------------- ------------- --------------
Total revenues............................ 26,687 10,780 46,908 19,106
------------- ------------- ------------- --------------
COSTS AND EXPENSES
Lease operations.............................. 4,469 2,684 8,169 5,388
Exploration:
Abandonments and impairments.............. 1,484 639 3,267 894
Seismic and other......................... 1,067 20 2,043 377
Natural gas services.......................... 1,158 795 2,027 1,456
Depreciation, depletion and amortization...... 6,892 5,548 11,949 10,840
General and administrative.................... 1,102 1,133 1,953 1,871
------------- ------------- ------------- --------------
Total costs and expenses.................. 16,172 10,819 29,408 20,826
------------- ------------- ------------- --------------
Operating income (loss)................... 10,515 (39) 17,500 (1,720)
------------- ------------- ------------- --------------
OTHER INCOME (EXPENSE)
Interest expense.............................. (644) (675) (1,255) (1,477)
Gain on sales of property and equipment....... 1,014 8,382 1,018 10,593
Other......................................... 19 280 65 367
------------- ------------- ------------- --------------
Total other income (expense).............. 389 7,987 (172) 9,483
------------- ------------- ------------- --------------
INCOME BEFORE INCOME TAXES......................... 10,904 7,948 17,328 7,763
INCOME TAX EXPENSE................................. - - - -
------------- ------------- ------------- --------------
NET INCOME......................................... $ 10,904 $ 7,948 $ 17,328 $ 7,763
============= ============= ============= ==============
Net income per common share:
Basic......................................... $ 1.19 $ .89 $ 1.89 $ .87
============= ============= ============= ==============
Diluted....................................... $ 1.15 $ .87 $ 1.84 $ .86
============= ============= ============= ==============
Weighted average common shares outstanding:
Basic......................................... 9,190 8,973 9,181 8,964
============= ============= ============= ==============
Diluted....................................... 9,492 9,107 9,431 9,063
============= ============= ============= ==============
</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>
SIX MONTHS ENDED
JUNE 30,
------------------------------
2000 1999
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<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.............................................................. $ 17,328 $ 7,763
Adjustments to reconcile net income to cash provided by
operating activities:
Depreciation, depletion and amortization............................ 11,949 10,840
Exploration costs................................................... 3,267 894
Gain on sales of property and equipment............................. (1,018) (10,593)
Other............................................................... 117 138
Changes in operating working capital:
Accounts receivable................................................. (6,556) 1,226
Accounts payable.................................................... 6,692 (3,003)
Other............................................................... (999) 196
------------- -------------
Net cash provided by operating activities...................... 30,780 7,461
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment..................................... (30,579) (9,333)
Proceeds from sales of property and equipment........................... 1,036 18,404
Other................................................................... 3 -
------------- -------------
Net cash provided by (used in) investing activities............ (29,540) 9,071
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt............................................ 500 -
Repayments of long-term debt............................................ - (15,900)
Proceeds from sale of common stock...................................... 84 42
------------- -------------
Net cash provided by (used in) financing activities............ 584 (15,858)
------------- -------------
NET INCREASE IN CASH AND CASH EQUIVALENTS.................................... 1,824 674
CASH AND CASH EQUIVALENTS
Beginning of period..................................................... 1,634 1,424
------------- -------------
End of period........................................................... $ 3,458 $ 2,098
============= =============
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized...................... $ 1,389 $ 1,587
============= =============
</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
JUNE 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 June 30, 2000 and for the interim periods ended June
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>
JUNE 30, DECEMBER 31,
2000 1999
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(IN THOUSANDS)
<S> <C> <C>
Secured Bank Credit Facility (matures July 31, 2002).............. $ 31,000 $ 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, 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 June 30,
2000, the Company's indebtedness under the credit facility consisted of $31
million of Eurodollar Loans at a rate of 8.9%.
In addition, the Company pays the banks a commitment fee equal to 1/4%
per annum on the unused portion of the revolving loan commitment. Interest on
the revolving loan and commitment fees are payable quarterly, and all
outstanding principal and interest will be due July 31, 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 June 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 six months ended June 30, 2000, the Company issued
8,158 shares of common stock to one officer in lieu of cash compensation
aggregating $116,616, which is included in general and administrative expense in
the accompanying consolidated financial statements. Subsequent to June 30, 2000,
the Company issued an additional 1,099 shares to the same officer in lieu of
cash compensation aggregating $36,937.
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 six month periods ended June 30, 2000 and 1999
are losses totaling $804,000 and $307,000, respectively.
7
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6. PROPERTY SALES
In January 1999, the Company completed the sale of its interests in eight
non-operated oil and gas wells located in Matagorda County, Texas for $5.2
million resulting in a gain of $1.8 million. In April 1999, the Company also
sold its interests in the Jalmat Field 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
Duvall County, Texas for $1 million. Since the cost of this prospect had been
fully amortized in prior periods, the Company recognized a gain equal to the
amount of proceeds during the second quarter of 2000.
7. INCOME TAXES
Since the Company's consolidation in May 1993, the Company has incurred
net income for financial reporting purposes aggregating $1.8 million and has
recognized cumulative tax losses of approximately $36.9 million which can be
carried forward and used to offset future taxable income. Tax loss carryforwards
begin to expire in 2008. Due to the uncertainty of realizing the related future
benefits from tax loss carryforwards, valuation allowances have been recorded to
the extent net deferred tax assets exceed net deferred tax liabilities at June
30, 2000 and December 31, 1999.
The tax effected temporary differences and tax loss carryforwards which
comprise net deferred tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
2000 1999
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(IN THOUSANDS)
<S> <C> <C>
Deferred tax assets (liabilities):
Depreciable and depletable property.................................... $ (12,099) $ (6,183)
Tax loss carryforwards................................................. 12,902 12,961
Other.................................................................. 25 956
Valuation allowance.................................................... (828) (7,734)
------------- -------------
Net deferred tax asset (liability).................................. $ - $ -
============= =============
</TABLE>
Substantially all of the valuation allowance at June 30, 2000 is
attributable to tax deductions derived from the exercise of employee stock
options, the tax benefit of which will be credited to additional paid-in capital
when realized. All of the differences between the statutory income tax rates and
the effective income tax rates are attributable to the change in the valuation
allowance.
8. ACCOUNTING PRONOUNCEMENTS
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, if any,
that SFAS 133 will have on its financial condition and results of operations
upon its adoption effective January 1, 2001.
In March 2000, the Financial Accounting Standards Board issued
Interpretation No. 44 (the "Interpretation") to Accounting Principles Board
Opinion No. 25 "Accounting for Stock Issued to Employees" which may adversely
affect the Company's results of operations in periods subsequent to its
effective date, July 1, 2000. The Interpretation requires certain stock options
which the Company repriced in April 1999 to be treated as variable awards.
Accordingly, the Company will be required to recognize compensation expense on
such options to the extent that the quoted market value of the Company's common
stock in future periods exceeds its quoted market value on the effective date
($31.94 per share). For the quarters ending September 30, 2000 and December 31,
2000, the Company expects to record
8
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compensation expense on repriced stock options of approximately $115,000 and
$9,000, respectively, for each $1 increase in the quoted market value above
$31.94 per share. However, any charge against earnings required pursuant to
the Interpretation will be a non-cash expense and will not affect cash flow
from operating activities.
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.
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 June 30, 2000 and
results of operations and cash flows for the periods ended June 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. However, low oil prices caused the Company to
temporarily suspend Trend drilling activities from April 1998 through September
1999, resulting in significant declines in oil production.
The Company has initiated several exploratory projects designed to reduce
its dependence on Trend drilling for future production and reserve growth. These
new areas include 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, and emphasize the development of long-life gas reserves. During
1999, the Company devoted a substantial portion of its capital expenditures to
these new areas. In the aggregate, exploratory drilling activities accounted for
about 32% of the Company's 4,790 MBOE of proved reserves added through
extensions and discoveries during 1999. The Company presently plans to spend
more than 50% of its capital expenditures in 2000 on exploration activities.
Although the Company holds a significant block of undeveloped acreage in
the Trend, the Company does not believe that the production performance of wells
previously drilled in the southern portion of this acreage block justify a
multiple-well drilling program. Instead, the Company plans to spend
approximately $19.4 million during 2000, of which $10.1 million was incurred at
June 30, 2000, to further exploit the developed portion of its Trend acreage by
drilling new horizontal wells in the areas that warrant development on an
increased density basis and by conducting secondary water frac operations on
existing wells.
10
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The Company follows the successful efforts method of accounting for its
oil and gas properties, whereby costs of productive wells, developmental dry
holes and productive leases are capitalized and amortized using the
unit-of-production method based on estimated proved reserves. Costs of unproved
properties are initially capitalized. Those properties with significant
acquisition costs are periodically assessed and any impairment in value is
charged to expense. The amount of impairment recognized on unproved properties
which are not individually significant is determined by amortizing the costs of
such properties within appropriate groups based on the Company's historical
experience, acquisition dates and average lease terms. Exploration costs,
including geological and geophysical expenses and delay rentals, are charged to
expense as incurred. Exploratory drilling costs, including the cost of
stratigraphic test wells, are initially capitalized but charged to expense if
and when the well is determined to be unsuccessful.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
----------------------------- -----------------------------
2000 1999 2000 1999
------------- ------------- ------------- --------------
<S> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (MBbls)........................ 627 476 1,176 949
Gas (MMcf)......................... 2,259 1,000 3,522 2,110
MBOE (1)........................... 1,004 643 1,763 1,301
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl)........................ $ 28.08 $ 15.77 $ 28.09 $ 13.51
Gas ($/Mcf)........................ $ 3.30 $ 2.55 $ 3.08 $ 2.03
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses........... $ 4.45 $ 4.17 $ 4.63 $ 4.14
Oil and gas depletion.............. $ 6.60 $ 8.38 $ 6.51 $ 8.08
NET WELLS DRILLED (3):
Exploratory Wells.................. .9 .4 2.1 1.5
Developmental Wells................ 10.6 - 22.7 -
</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 JUNE 30, 2000 COMPARED TO JUNE 30, 1999
REVENUES
Oil and gas sales increased 157% from $9.9 million in 1999 to $25.4
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 78% while average gas prices increased 29%.
Gas production increased 126% due primarily to an increase in the Company's
production capacity resulting from the completion of a new 70 MMcf per day gas
treatment facility in the Cotton Valley Pinnacle Reef area. Oil production
increased 32% 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 four wells in the Cotton Valley Pinnacle
Reef area and is currently drilling a fifth well. 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. The first three wells have
11
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been completed and are presently producing at a combined rate of
approximately 41 MMcf per day (20.5 MMcf to the Company's interest, net of
royalties and amounts payable under the vendor finance arrangement). The
fourth well is expected to be completed late in the third quarter.
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 67% from $2.7 million in 1999 to $4.5
million in 2000, while oil and gas production on a BOE basis increased 56%,
resulting in a 7% increase in production costs on a BOE basis from $4.17 in 1999
to $4.45 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 294% from $659,000 in 1999 to $2.6 million in
2000 due primarily to the charge off during the current quarter of $564,000 of
unproved property impairments and $920,000 of dry hole costs, as compared to
charges for both impairments and dry holes of only $639,000 during the 1999
period. Unproved property impairments in the 2000 period relate primarily to
acreage in Mississippi, while dry hole costs relate primarily to two
non-operated wells in Mississippi and Duvall County, Texas. 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 25% from $5.5
million in 1999 to $6.9 million in 2000 due primarily to a 56% increase in oil
and gas production on a BOE basis, offset in part by a 21% reduction in the
average depletion rate. Under the successful efforts method of accounting, costs
of oil and gas properties are amortized on a unit-of-production method based on
estimated proved reserves. The decline in the average depletion rate per BOE
from $8.38 in 1999 to $6.60 in 2000 was primarily due to higher reserve
estimates attributable to improved product prices.
INTEREST EXPENSE AND OTHER
Interest expense decreased 5% from $675,000 in 1999 to $644,000 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 current quarter was $31.9 million compared to $41.4 million in the
1999 period. The effective annual interest rate on bank debt, including bank
fees, during the current quarter was 9.4% compared to 7.8% in the 1999 period.
Capitalized interest was $99,000 for the current quarter compared to $152,000 in
the 1999 period.
During the second quarter of 1999, the Company recorded gains on sales of
property and equipment of $8.4 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. During the 2000 period, the Company sold 50% of its interests
in a prospect in Duvall County, Texas for $1 million, resulting in a gain of $1
million.
SIX MONTHS ENDED JUNE 30, 2000 COMPARED TO JUNE 30, 1999
REVENUES
Oil and gas sales increased 156% from $17.4 million in 1999 to $44.5
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 108% while average gas prices increased 52%.
Oil production increased 24% due primarily to added production from the
Company's horizontal drilling and water frac programs in the Trend. Gas
production increased 67% due primarily to an increase in the
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Company's production capacity resulting from the completion of a new 70 MMcf
per day gas treatment facility in the Cotton Valley Pinnacle Reef area.
To date, the Company has drilled four wells in the Cotton Valley Pinnacle
Reef area and is currently drilling a fifth well. 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. The first three wells have been
completed and are presently producing at a combined rate of approximately 41
MMcf per day (20.5 MMcf to the Company's interest, net of royalties and amounts
payable under the vendor finance arrangement). The fourth well is expected to be
completed late in the third quarter. 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 52% from $5.4 million in 1999 to $8.2
million in 2000, while oil and gas production on a BOE basis increased 36%,
resulting in a 12% increase in production costs on a BOE basis from $4.14 in
1999 to $4.63 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 308% from $1.3 million in 1999 to $5.3
million in 2000 due primarily to the charge off during 2000 of $1.7 million of
unproved property impairments, $1.5 million of dry hole costs and $1.9 million
of seismic costs, as compared to approximately $302,000 of impairments, $592,000
of dry hole costs and $238,000 of seismic costs during the six months ended June
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 two
non-operated wells in Duvall County, Texas and Mississippi. Substantially all of
the seismic costs in 2000 are attributable to exploratory prospects being
generated in Louisiana. 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 10% from $10.8
million in 1999 to $11.9 million in 2000 due primarily to a 36% increase in oil
and gas production on a BOE basis, offset in part by a 20% decrease in the
average depletion rate. Under the successful efforts method of accounting, costs
of oil and gas properties are amortized on a unit-of-production method based on
estimated proved reserves. The decline in the average depletion rate per BOE
from $8.08 in 1999 to $6.51 in 2000 was primarily due to higher reserve
estimates attributable to improved product prices.
INTEREST EXPENSE AND OTHER
Interest expense decreased 13% from $1.5 million in 1999 to $1.3 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 $31 million compared to $46.6 million
in the 1999 period. The effective annual interest rate on bank debt, including
bank fees, during the 2000 period was 9.2% compared to 7.7% in the 1999 period.
Capitalized interest during the 2000 period was $169,000 compared to $302,000 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 Duvall County,
Texas for $1 million, resulting in a gain of $1 million.
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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.
CAPITAL EXPENDITURES
The Company plans to spend $63 million on exploration and development
activities during 2000, of which $30.9 million has been incurred through June
30, 2000. The year 2000 estimates include $19.4 million in the Trend, $17.1
million in the Cotton Valley Pinnacle Reef area, $13.7 million on various
exploratory projects in Louisiana, $7.8 million in New Mexico and $5 million on
other projects.
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 June 30, 2000, the borrowing base was $48 million and the
outstanding advances were $31 million. Effective July 1, 2000, the borrowing
base was increased to $50 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 six months of 2000, the Company generated cash flow from
operating activities of $30.8 million, borrowed $500,000 on the credit facility
and spent $29.5 million on capital expenditures.
The Company's working capital deficit decreased from $6.6 million at
December 31, 1999 to $2.4 million at June 30, 2000. 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 non-current
liability, 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
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<PAGE>
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.
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 six months ended June 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 $3.1 million.
During 1998 and continuing into 1999, the oil and gas industry operated
in a depressed commodity price environment. Oil prices during the first quarter
of 1999 fell to their lowest levels in history when adjusted for inflation.
Since then, oil prices have improved significantly, and in March 2000, peaked at
over $34 per barrel on the NYMEX. Gas prices have also improved since March
1999, but like the oil markets, remain very volatile.
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
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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 position was subsequently terminated, and an aggregate loss of
approximately $800,000 was recorded during the six months ended June 30, 2000.
Also in February 2000, the Company entered into swap arrangements
covering 74,000 barrels of its oil production from July 2000 through December
2000 and from April 2001 through October 2001 at an average price of $22.49 per
barrel (ranging from a high of $25.00 per barrel in July 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.
INTEREST RATES
All of the Company's outstanding indebtedness at June 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 June 30, 2000 of $31 million, a change in interest rates of 25
basis points would affect annual interest payments by approximately $78,000.
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PART II. OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- --------------------------------------------------
<S> <C>
10.1 First Amendment to Seventh Restated Loan Agreement
dated as of July 1, 2000, among Clayton Williams
Energy, Inc., Warrior Gas Co., CWEI Acquisitions,
Inc., Bank One, Texas, N.A. and Union Bank of
California, N.A.
27 Financial Data Schedule
</TABLE>
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended June 30,
2000.
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CLAYTON WILLIAMS ENERGY, INC.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereto duly authorized.
CLAYTON WILLIAMS ENERGY, INC.
Date: August 8, 2000 By: /s/ L. PAUL LATHAM
---------------------------------------
L. Paul Latham
Executive Vice President and Chief
Operating Officer
Date: August 8, 2000 By: /s/ MEL G. RIGGS
---------------------------------------
Mel G. Riggs
Senior Vice President and Chief Financial
Officer
