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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 MARCH 31, 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
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(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 MAY 10, 2000.....9,183,082.
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CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS PAGE
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Consolidated Balance Sheets as of March 31, 2000
and December 31, 1999..................................................................... 3
Consolidated Statements of Operations for the three months
ended March 31, 2000 and 1999............................................................ 4
Consolidated Statements of Cash Flows for the three months
ended March 31, 2000 and 1999............................................................. 5
Notes to Consolidated Financial Statements.................................................. 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS....................................................... 9
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS.................................. 13
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................................................ 15
</TABLE>
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2
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
MARCH 31, DECEMBER 31,
2000 1999
--------------- ---------------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents......................................... $ 1,668 $ 1,634
Accounts receivable:
Trade, net.................................................... 2,889 2,661
Affiliates.................................................... 518 729
Oil and gas sales............................................. 12,121 9,846
Inventory......................................................... 590 717
Other............................................................. 475 313
--------------- ---------------
18,261 15,900
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PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method................. 448,295 436,831
Natural gas gathering and processing systems...................... 12,523 9,810
Other............................................................. 10,362 10,350
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471,180 456,991
Less accumulated depreciation, depletion and amortization......... (369,030) (363,985)
--------------- ---------------
Property and equipment, net................................... 102,150 93,006
--------------- ---------------
OTHER ASSETS........................................................... 256 260
--------------- ---------------
$ 120,667 $ 109,166
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES Accounts payable:
Trade......................................................... $ 16,598 $ 13,648
Affiliates.................................................... 251 310
Oil and gas sales............................................. 8,513 7,785
Accrued liabilities and other..................................... 688 806
--------------- ---------------
26,050 22,549
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LONG-TERM DEBT......................................................... 32,000 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 - 9,177,999 shares in 2000 and 9,167,779
shares in 1999................................................... 918 917
Additional paid-in capital........................................ 70,765 70,690
Retained deficit.................................................. (9,066) (15,490)
--------------- ---------------
62,617 56,117
--------------- ---------------
$ 120,667 $ 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
MARCH 31,
--------------------------------
2000 1999
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<S> <C> <C>
REVENUES
Oil and gas sales ........................................... $ 19,102 $ 7,521
Natural gas services ........................................ 1,119 805
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Total revenues .......................................... 20,221 8,326
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COSTS AND EXPENSES
Lease operations ............................................ 3,700 2,704
Exploration:
Abandonments and impairments ............................ 1,783 255
Seismic and other ....................................... 976 357
Natural gas services ........................................ 869 661
Depreciation, depletion and amortization..................... 5,057 5,292
General and administrative .................................. 851 738
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Total costs and expenses ................................ 13,236 10,007
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Operating income (loss) ................................. 6,985 (1,681)
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OTHER INCOME (EXPENSE)
Interest expense ............................................ (611) (802)
Gain on sales of property and equipment 4 2,211
Other ....................................................... 46 87
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Total other income (expense) ............................ (561) 1,496
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INCOME (LOSS) BEFORE INCOME TAXES ................................ 6,424 (185)
INCOME TAX EXPENSE ............................................... - -
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NET INCOME (LOSS) ................................................ $ 6,424 $ (185)
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Net income (loss) per common share:
Basic ....................................................... $ .70 $ (.02)
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Diluted ..................................................... $ .69 $ (.02)
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Weighted average common shares outstanding:
Basic ....................................................... 9,172 8,954
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Diluted ..................................................... 9,373 8,954
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</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>
THREE MONTHS ENDED
MARCH 31,
---------------------------
2000 1999
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) ..................................................... $ 6,424 $ (185)
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
Depreciation, depletion and amortization .......................... 5,057 5,292
Exploration costs ................................................. 1,783 255
Gain on sales of property and equipment ........................... (4) (2,211)
Other ............................................................. 59 73
Changes in operating working capital:
Accounts receivable ............................................... (2,292) 4,599
Accounts payable .................................................. 3,231 (2,538)
Other ............................................................. (151) (57)
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Net cash provided by operating activities .................... 14,107 5,228
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment ................................... (15,602) (3,006)
Proceeds from sales of property and equipment ......................... 10 5,667
Other ................................................................. 2 -
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Net cash provided by (used in) investing activities .......... (15,590) 2,661
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt .......................................... 1,500 -
Repayments of long-term debt .......................................... - (1,900)
Proceeds from sale of common stock .................................... 17 42
-------- --------
Net cash provided by (used in) financing activities .......... 1,517 (1,858)
-------- --------
NET INCREASE IN CASH AND CASH EQUIVALENTS .................................. 34 6,031
CASH AND CASH EQUIVALENTS
Beginning of period ................................................... 1,634 1,424
-------- --------
End of period ......................................................... $ 1,668 $ 7,455
======== ========
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized .................... $ 730 $ 817
======== ========
</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
MARCH 31, 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 March 31, 2000 and for the interim periods ended
March 31, 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>
MARCH 31, DECEMBER 31,
2000 1999
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(IN THOUSANDS)
<S> <C> <C>
Secured Bank Credit Facility (matures July 31, 2001).............. $ 32,000 $ 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.
As of March 31, 2000, the borrowing base established by the banks was
$48 million, with no monthly commitment reductions. The borrowing base is
scheduled for redetermination in May 2000.
All outstanding balances on the credit facility may be designated, at
the Company's option, as either "Base Rate Loans" or "Eurodollar Loans" (as
defined in the loan agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 3/8% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin
ranging from 1.75% to 2.5% per annum. At March 31, 2000, the Company's
indebtedness under the credit facility consisted of $28 million of Eurodollar
Loans at a rate of 8.4% and $4 million of Base Rate Loans at a rate of 9.3%.
In addition, the Company pays the banks a commitment fee equal to 1/4%
per annum on the unused portion of the revolving loan commitment. Interest on
the revolving loan and commitment fees are payable quarterly, and all
outstanding principal and interest will be due July 31, 2001.
The loan agreement contains financial covenants that are computed
quarterly and require the Company to maintain minimum levels of working
capital, cash flow and net tangible assets. The Company was in compliance
with all of the financial and non-financial covenants at March 31, 2000.
4. STOCK COMPENSATION PLANS
In May 1995, the Company's Board of Directors adopted the Executive
Incentive Stock Compensation Plan, permitting the Company to pay all or part
of selected executives' salaries in shares of common stock in lieu of cash.
The Company reserved 500,000 shares of common stock for issuance under this
plan. During the three months ended March 31, 2000, the Company issued 4,920
shares of common stock to one officer in lieu of cash compensation
aggregating $59,195. Subsequent to March 31, 2000, the Company issued an
additional 2,562 shares to the same officer in lieu of cash compensation
aggregating $39,845. The amounts of such compensation are included in general
and administrative expense in the accompanying consolidated financial
statements.
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 three month
periods ended March 31, 2000 and 1999 are losses totaling $288,000 and net
losses totaling $173,000 (comprised of losses of $243,000, partially offset
by gains of $70,000), respectively.
7
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6. PROPERTY SALES
In January 1999, the Company completed the sale of its interests in
eight non-operated oil and gas wells located in Matagorda County, Texas for
$5.2 million resulting in a gain of $1.8 million. In April 1999, the Company
also sold its interests in the Jalmat Field located in Lea County, New Mexico
for $12.5 million and recorded a gain of $8.4 million.
In April 2000, the Company sold 50% of its interest in a prospect in
Duvall County, Texas for $1 million. The sale resulted in a gain of
approximately $1 million to be reported during the second quarter of 2000.
7. INCOME TAXES
No provisions for income tax expense were required during the periods
presented since the Company has net operating loss carryforwards available to
offset any taxable income generated during such periods. Due to the
uncertainty of realizing the related future benefits from these tax loss
carryforwards, valuation allowances were recorded at March 31, 2000 and 1999
to the extent net deferred tax assets exceed net deferred tax liabilities.
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. SFAS 133 will be adopted in
2001 and is not expected to have a material effect on the Company's financial
condition or operations.
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
compensatory. 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. Since the Company cannot accurately
predict the quoted market value at any future date, the Company cannot
presently quantify the level of compensation expense which may be reported in
future periods. 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.
8
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ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Certain statements in this Form 10-Q constitute "forward-looking
statements" within the meaning of Section 27A of the Securities Act of 1933,
as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements, other than statements of historical facts, included
in this Form 10-Q that address activities, events or developments that
Clayton Williams Energy, Inc. and its subsidiaries (the "Company") expects,
projects, believes or anticipates will or may occur in the future, including
such matters as oil and gas reserves, future drilling and operations, future
production of oil and gas, future net cash flows, future capital expenditures
and other such matters, are forward-looking statements. Such forward-looking
statements involve known and unknown risks, uncertainties, and other factors
which may cause the actual results, performance, or achievements of the
Company to be materially different from any future results, performance, or
achievements expressed or implied by such forward-looking statements. Such
factors include, among others, the following: the volatility of oil and gas
prices, the Company's drilling results, the Company's ability to replace
short-lived reserves, the availability of capital resources, the reliance
upon estimates of proved reserves, operating hazards and uninsured risks,
competition, government regulation, the ability of the Company to implement
its business strategy, and other factors referenced in this Form 10-Q.
The following discussion is intended to assist in understanding the
Company's historical consolidated financial position at March 31, 2000 and
results of operations and cash flows for the periods ended March 31, 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 from 1997 levels.
Since 1997, 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 $11.9 million during 2000, of which $6.6 million was incurred
at March 31, 2000, to further exploit the developed portion of its Trend
acreage by drilling new horizontal wells in the areas that warrant
development on an increased density basis and by conducting secondary water
frac operations on existing wells.
9
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The Company follows the successful efforts method of accounting for
its oil and gas properties, whereby costs of productive wells, developmental
dry holes and productive leases are capitalized and amortized using the
unit-of-production method based on estimated proved reserves. Costs of
unproved properties are initially capitalized. Those properties with
significant acquisition costs are periodically assessed and any impairment in
value is charged to expense. The amount of impairment recognized on unproved
properties which are not individually significant is determined by amortizing
the costs of such properties within appropriate groups based on the Company's
historical experience, acquisition dates and average lease terms. Exploration
costs, including geological and geophysical expenses and delay rentals, are
charged to expense as incurred. Exploratory drilling costs, including the
cost of stratigraphic test wells, are initially capitalized but charged to
expense if and when the well is determined to be unsuccessful.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-----------------------------------
2000 1999
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<S> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (MBbls).................................................. 549 473
Gas (MMcf)................................................... 1,263 1,110
MBOE (1)..................................................... 760 658
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl).................................................. $ 28.11 $ 11.42
Gas ($/Mcf).................................................. $ 2.70 $ 1.57
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses..................................... $ 4.87 $ 4.11
Oil and gas depletion........................................ $ 6.38 $ 7.80
NET WELLS DRILLED (3):
Exploratory Wells............................................ 1.2 1.1
Developmental Wells.......................................... 12.1 -
</TABLE>
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(1) Gas is converted to barrel of oil equivalents (BOE) at the ratio of six
Mcf of gas to one Bbl of oil.
(2) Includes effects of hedging transactions.
(3) Excludes wells being drilled or completed at the end of each period.
THREE MONTHS ENDED MARCH 31, 2000 COMPARED TO MARCH 31, 1999
REVENUES
Oil and gas sales increased 155% from $7.5 million in 1999 to $19.1
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 146% while average gas prices increased
72%. Oil production increased 16% due primarily to added production from the
Company's horizontal drilling and water frac programs in the Trend. Gas
production increased 14% due primarily to production from the Cotton Valley
Pinnacle Reef area, offset in part by the loss of production from a large gas
property sold in the second quarter of 1999.
The Company currently has two wells on production in the Cotton Valley
Pinnacle Reef area, the J. C. Fazzino Unit #1, the Company's initial
discovery well, and the J. C. Fazzino Unit #2, a well drilled in the same
reef under a vendor financing arrangement. Due to limited plant capacity,
combined gas production from these wells during the first quarter of 2000 was
restricted to 15 MMcf per day. The Company completed construction on a new 70
MMcf per day plant in early April. Since the completion
10
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of the new plant, the Company has produced the Fazzino #2 at an average rate
of 27.3 MMcf per day (10.9 MMcf to the Company's interest, net of royalties
and amounts payable to the vendor finance group), and has produced the
Fazzino #1 at an average rate of 5.4 MMcf per day (4.4 MMcf to the Company's
interest, net of royalties). 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 37% from $2.7 million in 1999 to
$3.7 million in 2000, while oil and gas production on a BOE basis increased
16%, resulting in an 18% increase in production costs on a BOE basis from
$4.11 in 1999 to $4.87 in 2000. Such increase was due primarily to increased
production taxes attributable to higher oil and gas prices in 2000.
Exploration costs increased 358% from $612,000 in 1999 to $2.8 million
in 2000 due primarily to the charge off during the current quarter of $1.2
million of unproved property impairments and $624,000 of dry hole costs, as
compared to charges for both impairments and dry holes of only $255,000
during the 1999 period. Most of the unproved property impairments relate to
acreage in the Glen Rose area of Texas, and the dry hole costs relate to a
non-operated well in 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 decreased 4% from
$5.3 million in 1999 to $5.1 million in 2000 due primarily to an 18%
reduction in the average depletion rate, offset largely by a 16% 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 decline in
the average depletion rate per BOE from $7.80 in 1999 to $6.38 in 2000 was
primarily due to higher reserve estimates attributable to improved product
prices.
General and administrative expenses increased 15% from $738,000 in
1999 to $851,000 in 2000 due primarily to higher personnel costs during the
current quarter attributable to increased levels of drilling and operating
activities. Low product prices in 1998 caused the Company to curtail its
operations 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 these
temporary measures.
INTEREST EXPENSE AND OTHER
Interest expense decreased 24% from $802,000 in 1999 to $611,000 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 $30.1 million compared to $51.8 million in the 1999 period. The
effective annual interest rate on bank debt, including bank fees, during the
current quarter was 9.1%, compared to 7.4% in the 1999 period.
During the first quarter of 1999, the Company recorded a gain on sales
of property and equipment of $1.8 million on the sale of the Company's
interest in eight non-operated gas wells in Matagorda County, Texas.
11
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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 $44.3 million on exploration and
development activities during 2000, of which $16.9 million has been incurred
through March 31, 2000. The year 2000 estimates include $11.9 million in the
Trend, $12.1 million in the Cotton Valley Pinnacle Reef area, $10.2 million
on various exploratory projects in Louisiana and $10.1 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 March 31, 2000, the borrowing base was $48
million and the outstanding advances were $32 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 current quarter, the Company generated cash flow from
operating activities of $14.1 million, borrowed $1.5 million on the credit
facility and spent $15.6 million on capital expenditures.
The Company's working capital deficit increased from $6.6 million at
December 31, 1999 to $7.8 million at March 31, 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. However, working capital will increase
in future periods as funds are advanced on the credit facility to finance the
Company's capital expenditures program.
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
12
<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 first quarter of 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 gross revenues of approximately
$675,000 during the three month period.
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
13
<PAGE>
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 at an aggregate
loss of approximately $800,000, of which $286,000 was recognized during the
first quarter of 2000.
Also in February 2000, the Company entered into swap arrangements
covering 740,000 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 170,000 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 March 31, 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 March 31, 2000 of $32 million, a change
in interest rates of 25 basis points would affect annual interest payments by
$80,000.
14
<PAGE>
PART II. OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- ---------------------------------------------------
<S> <C> <C>
27 Financial Data Schedule
</TABLE>
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended March 31,
2000.
15
<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: May 11, 2000 By: /s/ L. Paul Latham
-----------------------------------------
L. Paul Latham
Executive Vice President and Chief
Operating Officer
Date: May 11, 2000 By: /s/ Mel G. Riggs
-----------------------------------------
Mel G. Riggs
Senior Vice President and Chief Financial
Officer
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS OF THE REGISTRANT FOR THE QUARTER ENDED
MARCH 31, 2000 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<CASH> 1,668
<SECURITIES> 0
<RECEIVABLES> 15,528
<ALLOWANCES> 0
<INVENTORY> 590
<CURRENT-ASSETS> 18,261
<PP&E> 471,180
<DEPRECIATION> 369,030
<TOTAL-ASSETS> 120,667
<CURRENT-LIABILITIES> 26,050
<BONDS> 32,000
0
0
<COMMON> 918
<OTHER-SE> 61,699
<TOTAL-LIABILITY-AND-EQUITY> 120,667
<SALES> 19,102
<TOTAL-REVENUES> 20,221
<CGS> 3,700
<TOTAL-COSTS> 13,236
<OTHER-EXPENSES> (50)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 611
<INCOME-PRETAX> 6,424
<INCOME-TAX> 0
<INCOME-CONTINUING> 6,424
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,424
<EPS-BASIC> 0.70
<EPS-DILUTED> 0.69
</TABLE>
