<PAGE>
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
+--+
|XX|
+--+
Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1999
or
+--+
| |
+--+
Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from _________ to _________
COMMISSION FILE NO. 0-20838
CLAYTON WILLIAMS ENERGY, INC.
-----------------------------
(Exact name of Registrant as specified in its charter)
DELAWARE 75-2396863
------------------------------- ----------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
6 DESTA DRIVE, SUITE 6500, MIDLAND, TEXAS 79705-5510
----------------------------------------- ----------
(Address of principal executive offices) (Zip code)
Registrant's Telephone Number, including area code: (915) 682-6324
Not applicable
---------------------------------------------------------------
(Former name, former address and former fiscal year, if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
+--+ +--+
|xx| | |
YES +--+ NO +--+
NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF MAY 7, 1999........8,974,170
===============================================================================
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
<TABLE>
<CAPTION>
ITEM 1. FINANCIAL STATEMENTS PAGE
- ------- -------------------- ----
<S> <C>
Consolidated Balance Sheets as of March 31, 1999
and December 31, 1998................................................ 3
Consolidated Statements of Operations for the three months
ended March 31, 1999 and 1998....................................... 4
Consolidated Statements of Cash Flows for the three months
ended March 31, 1999 and 1998........................................ 5
Notes to Consolidated Financial Statements............................. 6
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS........................ 9
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS............. 14
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K....................................... 16
</TABLE>
===============================================================================
2
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
--------------- ---------------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents............................................. $ 7,455 $ 1,424
Accounts receivable:
Trade, net.......................................................... 1,172 6,782
Affiliates.......................................................... 158 244
Oil and gas sales................................................... 4,725 3,628
Inventory............................................................. 1,338 1,230
Property held for resale.............................................. 4,154 7,521
Other................................................................. 260 482
--------------- ---------------
19,262 21,311
--------------- ---------------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method..................... 425,071 424,360
Natural gas gathering and processing systems.......................... 8,543 8,292
Other................................................................. 10,483 10,480
--------------- ---------------
444,097 443,132
Less accumulated depreciation, depletion and amortization............. (348,619) (343,857)
--------------- ---------------
Property and equipment, net......................................... 95,478 99,275
--------------- ---------------
OTHER ASSETS............................................................. 63 67
--------------- ---------------
$ 114,803 $ 120,653
=============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade............................................................... $ 11,485 $ 16,384
Affiliates.......................................................... 100 65
Oil and gas sales................................................... 4,592 3,433
Current maturities of long-term debt.................................. 17,750 15,800
Accrued liabilities and other......................................... 1,302 1,477
--------------- ---------------
35,229 37,159
--------------- ---------------
LONG-TERM DEBT........................................................... 35,250 39,100
--------------- ---------------
STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share; authorized - 3,000,000
shares; issued and outstanding - none................................ - -
Common stock, par value $.10 per share; authorized - 15,000,000
shares; issued - 8,965,883 shares in 1999 and 8,937,561
shares in 1998....................................................... 897 894
Additional paid-in capital............................................ 69,856 69,744
Retained deficit...................................................... (26,429) (26,244)
--------------- ---------------
44,324 44,394
--------------- ---------------
$ 114,803 $ 120,653
=============== ===============
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
3
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-----------------------------------
1999 1998
--------------- ---------------
<S> <C> <C>
REVENUES
Oil and gas sales................................................... $ 7,521 $ 16,829
Natural gas services................................................ 805 936
--------------- ---------------
Total revenues.................................................... 8,326 17,765
--------------- ---------------
COSTS AND EXPENSES
Lease operations.................................................... 2,704 3,988
Exploration:
Abandonments and impairments...................................... 255 413
Seismic and other................................................. 357 1,233
Natural gas services................................................ 661 758
Depreciation, depletion and amortization............................ 5,292 8,874
General and administrative.......................................... 738 1,077
--------------- ---------------
Total costs and expenses.......................................... 10,007 16,343
--------------- ---------------
Operating income (loss)........................................... (1,681) 1,422
--------------- ---------------
OTHER INCOME (EXPENSE)
Interest expense.................................................... (802) (477)
Gain on sales of property and equipment............................. 2,211 13
Other............................................................... 87 4
--------------- ---------------
Total other income (expense)...................................... 1,496 (460)
--------------- ---------------
INCOME (LOSS) BEFORE INCOME TAXES...................................... (185) 962
INCOME TAX EXPENSE..................................................... - -
--------------- ---------------
NET INCOME (LOSS)...................................................... $ (185) $ 962
=============== ===============
Net income (loss) per common share:
Basic............................................................... $ (.02) $ .11
================ ===============
Diluted............................................................. $ (.02) $ .11
================ ===============
Weighted average common shares outstanding:
Basic............................................................... 8,954 8,889
================ ===============
Diluted............................................................. 8,954 9,084
================ ===============
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
4
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
------------------------------
1999 1998
------------- -------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss).......................................................... $ (185) $ 962
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
Depreciation, depletion and amortization............................... 5,292 8,874
Exploration costs...................................................... 255 413
Gain on sales of property and equipment................................ (2,211) (13)
Other.................................................................. 73 68
Changes in operating working capital:
Accounts receivable.................................................... 4,599 3,402
Accounts payable....................................................... (2,538) 812
Other.................................................................. (57) 1,547
------------- -------------
Net cash provided by operating activities......................... 5,228 16,065
------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment........................................ (3,006) (14,677)
Proceeds from sales of property and equipment.............................. 5,667 13
------------- -------------
Net cash provided by (used in) investing activities............... 2,661 (14,664)
------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of long-term debt............................................... (1,900) (2,300)
Proceeds from sale of common stock......................................... 42 -
------------- -------------
Net cash used in financing activities............................. (1,858) (2,300)
------------- -------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................ 6,031 (899)
CASH AND CASH EQUIVALENTS
Beginning of period........................................................ 1,424 2,150
------------- -------------
End of period.............................................................. $ 7,455 $ 1,251
============= =============
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized......................... $ 817 $ 508
============= =============
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
5
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. NATURE OF OPERATIONS
Clayton Williams Energy, Inc. and its subsidiaries (collectively, the
"Company") is an independent oil and gas company engaged in the exploration
for and development and production of oil and natural gas primarily in South
and East Texas, Southeastern New Mexico, the Texas Gulf Coast, Louisiana and
Mississippi.
Substantially all of the Company's oil and gas production is sold
under short-term contracts which are market-sensitive. Accordingly, the
Company's financial condition, results of operations, and capital resources
are highly dependent upon prevailing market prices of, and demand for, oil
and natural gas. These commodity prices are subject to wide fluctuations and
market uncertainties due to a variety of factors that are beyond the control
of the Company. These factors include the level of global demand for
petroleum products, foreign supply of oil and gas, the establishment of and
compliance with production quotas by oil-exporting countries, weather
conditions, the price and availability of alternative fuels, and overall
economic conditions, both foreign and domestic. From time to time, the
Company utilizes hedging transactions with respect to a portion of its oil
and gas production to mitigate its exposure to price fluctuations (see Note
6).
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, 1999 and for the interim periods ended
March 31, 1999 and 1998 include all adjustments, consisting only of normal
recurring accruals, which are necessary for a fair presentation in accordance
with generally accepted accounting principles. These interim results are not
necessarily indicative of the results to be expected for the year ending
December 31, 1999.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted in this Form 10-Q
pursuant to the rules and regulations of the Securities and Exchange
Commission. These consolidated financial statements should be read in
conjunction with the audited consolidated financial statements and notes
thereto included in the Company's 1998 Form 10-K.
3. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
--------------- ---------------
(IN THOUSANDS)
<S> <C> <C>
Secured Bank Credit Facility (matures July 31, 2001).............. $ 53,000 $ 54,900
Less current maturities........................................... (17,750) (15,800)
---------------- ----------------
$ 35,250 $ 39,100
================ ================
</TABLE>
6
<PAGE>
The Company's secured bank credit facility (the "Credit Facility")
provides for a revolving loan facility in an amount not to exceed the lesser
of the borrowing base, as established by the banks, or that portion of the
borrowing base determined by the Company to be the elected borrowing limit.
The borrowing base, which is based on the discounted present value of future
net revenues from oil and gas production, is subject to redetermination at
any time, but at least semi-annually, and is made at the discretion of the
banks. If, at any time, the redetermined borrowing base is less than the
amount of outstanding indebtedness, the Company will be required to (i)
pledge additional collateral, (ii) prepay the excess in not more than five
equal monthly installments, or (iii) elect to convert the entire amount of
outstanding indebtedness to a term obligation based on amortization formulas
set forth in the loan agreement. Substantially all of the Company's oil and
gas properties are pledged to secure advances under the credit facility.
In March 1999, the banks established the borrowing base at $53 million
and provided for an automatic reduction of the borrowing base to $43 million
upon sale of the Company's Jalmat assets (see Note 4) and further provided
for monthly commitment reductions of $650,000 beginning in July 1999. In
April 1999, the Company repaid $11.5 million of indebtedness on the Credit
Facility with proceeds from the Jalmat sale. The adjusted borrowing base will
remain in effect until the next scheduled borrowing base redetermination in
November 1999.
All outstanding balances on the Credit Facility may be designated, at
the Company's option, as either "Base Rate Loans" or "Eurodollar Loans" (as
defined in the loan agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 3/8% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin
ranging from 1.75% to 2.5% per annum. At March 31, 1999, the Company's
indebtedness under the credit facility consisted of $48 million of Eurodollar
Loans at a rate of 7.5% and $5 million of Base Rate Loans at a rate of 8.1%.
In addition, the Company pays the banks a commitment fee equal to 1/4%
per annum on the unused portion of the revolving loan commitment. Interest on
the revolving loan and commitment fees are payable quarterly, and all
outstanding principal and interest will be due July 31, 2001.
The loan agreement contains financial covenants that are computed
quarterly and require the Company to maintain minimum levels of working
capital, cash flow and net tangible assets. The Company was in compliance
with all of the financial covenants at March 31, 1999.
4. PROPERTY HELD FOR RESALE
In March 1999, the Company entered into a definitive agreement for the
sale of its interests in the Jalmat Field located in Lea County, New Mexico
for $12.5 million. The Jalmat sale was consummated in April 1999 and resulted
in a gain of approximately $8.2 million to be reported during the second
quarter of 1999. Substantially all of the proceeds from this sale were used
to reduce indebtedness on the Credit Facility. The net book value of these
assets has been classified as a current asset in the accompanying
consolidated balance sheet.
5. STOCK COMPENSATION PLANS
In May 1995, the Company's Board of Directors adopted the Executive
Incentive Stock Compensation Plan, permitting the Company to pay all or part
of selected executives' salaries in shares of common stock in lieu of cash.
The Company reserved 500,000 shares of common stock for issuance under this
plan. During the three months ended March 31, 1999, the Company issued 11,629
shares of common stock to one officer in lieu of cash compensation
aggregating $63,114. Subsequent to March 31, 1999, the Company issued an
additional 8,287 shares to the same officer in lieu of cash compensation
aggregating $43,489. The amounts of such compensation are included in general
and administrative expense in the accompanying consolidated financial
statements.
7
<PAGE>
6. FORWARD SALE TRANSACTIONS
From time to time, the Company utilizes forward sale and other
financial option arrangements, such as swaps and collars, to reduce price
risks on the sale of its oil and gas production. The Company accounts for
such arrangements as hedging activities and, accordingly, records all
realized gains and losses as oil and gas revenues in the period the hedged
production is sold. Included in oil and gas revenues during the three month
periods ended March 31, 1999 and 1998 are net losses totaling $173,000
(comprised of losses of $243,000, partially offset by gains of $70,000) and
gains totaling $2,624,000, respectively.
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, 1999 and 1998
to the extent net deferred tax assets exceed net deferred tax liabilities.
8. RECENT ACCOUNTING PRONOUNCEMENT
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133
establishes accounting and reporting standards for derivative instruments and
hedging activities. It requires that derivatives be recognized as assets or
liabilities and measured at their fair value. SFAS 133 will be adopted in
2000 and is not expected to have a material effect on the Company's financial
condition or operations.
8
<PAGE>
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, 1999 and
results of operations and cash flows for the periods ended March 31, 1999 and
1998. This discussion should be read in conjunction with the Company's Form
10-K for the year ended December 31, 1998 and the consolidated financial
statements and notes thereto included in this Form 10-Q.
OVERVIEW
Prior to 1998, the Company and its predecessors concentrated their
drilling activities in the Cretaceous Trend (the "Trend") which extends from
south Texas through east Texas, Louisiana and other southern states and
includes the Austin Chalk, Buda and Georgetown formations. Oil and gas
production in the Trend is generally characterized by a high initial
production rate, followed by a steep rate of decline. In order to maintain
its oil and gas reserve base, production levels and cash flow from
operations, the Company has been required to maintain or increase its level
of drilling activity and achieve comparable or improved results from such
activities. In response to low oil prices, the Company suspended its Trend
drilling activities in April 1998 and has no plans to resume drilling in that
area until oil prices improve and stabilize.
Beginning in 1997, the Company initiated several exploratory projects
designed to reduce its dependence on Trend drilling for future production and
reserve growth. These new areas include other formations in the vicinity of
its core properties in east central Texas, as well as south Texas, Louisiana
and Mississippi, and emphasize the development of long-life gas reserves.
During 1998, the Company devoted a substantial portion of its capital
expenditures to these new areas. Except for its Cotton Valley Pinnacle Reef
play, the Company has no present plans to incur any significant capital
expenditures in these new areas in 1999. However, the Company may farmout to
industry partners its position on prospects where exploratory drilling is
warranted and attempt to retain a carried interest in any wells drilled.
In January 1999, the Company completed the J. C. Fazzino Unit #1, a
Cotton Valley Pinnacle Reef gas well in Robertson County, Texas in which the
Company owns a 100% working interest. The Company's net proved reserves on
this well are estimated to be 7.6 Bcf of gas. Construction of a gas pipeline
and treatment facility for the well has been completed and arrangements are
currently being made to acidize the well in an attempt to improve initial
flow rates. The Company expects to begin selling gas production from the
Fazzino #1 in late May 1999.
9
<PAGE>
Based upon data obtained during post-completion operations, the
Company determined that the Fazzino #1 penetrated the edge of the reef. As a
result, the Company has begun drilling operations on the J. C. Fazzino Unit
#2 in an attempt to penetrate the core of the reef. Approximately 67% of the
$4.5 million cost to drill and complete the Fazzino #2 will be financed
through a non-recourse vendor financing arrangement which permits the Company
to pay participating vendors for services and materials out of a dedicated
percentage of revenues from the well. Any other wells drilled in this area
within the five-year term of the agreement are also subject to this vendor
financing arrangement. The Company expects to finalize drilling and
completion operations on the Fazzino #2 during the third quarter of 1999.
During 1998 and continuing throughout the first quarter of 1999, the
oil and gas industry has operated in a depressed commodity price environment.
Anticipating the adverse effects that low product prices could have on its
capital resources, the Company initiated efforts late in 1998 to sell its
interests in two properties in order to reduce the amount of outstanding
indebtedness on the Credit Facility. In January 1999, the Company sold its
interest in eight non-operated oil and gas wells located in Matagorda County,
Texas for $5.2 million, and sold its interests in the Jalmat Field located in
Lea County, New Mexico for $12.5 million in April 1999. In the aggregate,
these properties accounted for approximately 9% of the Company's 1998 annual
oil and gas production on a BOE basis and 22% of the Company's estimated
future net revenues (discounted at 10%) at December 31, 1998.
A significant portion of the Company's capital expenditures during
1998 and the first three months of 1999 have been spent on acquisitions of
exploratory acreage, exploratory wells which have not been completed and
exploratory wells which have resulted in dry holes. Accordingly, production
from wells drilled subsequent to March 31, 1998 has not been sufficient to
offset the recent declines in oil and gas production attributable to the
suspension of Trend drilling and the sales of producing properties.
Furthermore, until these new projects are completed and establish commercial
levels of production, there can be no assurance that the Company will be
successful in its efforts to replace such production declines.
The Company follows the successful efforts method of accounting for
its oil and gas properties, whereby costs of productive wells, developmental
dry holes and productive leases are capitalized and amortized using the
unit-of-production method based on estimated proved reserves. Costs of
unproved properties are initially capitalized. Those properties with
significant acquisition costs are periodically assessed, and any impairment
in value is charged to expense. The amount of impairment recognized on
unproved properties which are not individually significant is determined by
amortizing the costs of such properties within appropriate groups based on
the Company's historical experience, acquisition dates and average lease
terms. Exploration costs, including geological and geophysical expenses and
delay rentals, are charged to expense as incurred. Exploratory drilling
costs, including the cost of stratigraphic test wells, are initially
capitalized but charged to expense if and when the well is determined to be
unsuccessful.
10
<PAGE>
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,
-------------------------------
1999 1998
------------- -------------
<S> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (MBbls)............................................ 473 793
Gas (MMcf)............................................. 1,110 1,253
MBOE (1)............................................... 658 1,002
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl)............................................ $ 11.42 $ 16.99
Gas ($/Mcf)............................................ $ 1.57 $ 2.61
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses............................... $ 4.11 $ 3.98
Oil and gas depletion.................................. $ 7.80 $ 8.60
NET WELLS DRILLED (3):
Exploratory Wells...................................... 1.1 1.0
Developmental Wells.................................... - 5.4
</TABLE>
(1) Gas is converted to barrel of oil equivalents (BOE) at the ratio of
six Mcf of gas to one Bbl of oil.
(2) Includes effects of hedging transactions.
(3) Excludes wells being drilled or completed at the end of each period.
THREE MONTHS ENDED MARCH 31, 1999 COMPARED TO MARCH 31, 1998
REVENUES
Oil and gas sales decreased 55% from $16.8 million in 1998 to $7.5
million in 1999 due primarily to a combination of lower oil and gas prices
and a 34% decline in oil and gas production on a BOE basis. The Company's
average price per barrel of oil declined 33% after giving effect to a $.21
per barrel loss on hedging activities in the 1999 period as compared to a
$2.76 per barrel gain in the 1998 period. Average gas prices also declined
40% after giving effect to a $.06 per Mcf hedging loss in the 1999 period as
compared to a $.34 per Mcf gain in the 1998 period. Low product prices also
had a negative impact on the volume of oil and gas produced during the
current quarter. In April 1998, the Company suspended its Trend drilling
program until oil prices improve and stabilize. In addition, the Company sold
its interests in two producing properties, one in January 1999 and one in
April 1999, in order to mitigate the adverse effects of low product prices on
its capital resources. Initial production from the Company's Cotton Valley
Pinnacle Reef gas discovery has been delayed due to the construction of a gas
pipeline and treatment facility. Accordingly, production from wells drilled
subsequent to March 31, 1998 has not been sufficient to offset the recent
declines in oil and gas production attributable to the suspension of Trend
drilling and the sales of producing properties. Furthermore, until these
wells and other exploratory projects establish and sustain commercial levels
of production, there can be no assurance that the Company will be successful
in its efforts to offset the decline in production.
Revenues from natural gas services decreased 14% from $936,000 in
1998 to $805,000 in 1999 due primarily to a decrease in contract volumes.
11
<PAGE>
COSTS AND EXPENSES
Lease operations expenses decreased 33% from $4 million in 1998 to
$2.7 million in 1999 due primarily to cost reduction measures implemented by
the Company and, to a lesser extent, lower production taxes resulting from
significant declines in oil and gas sales. Oil and gas production on a BOE
basis decreased 34% during the current quarter, causing a 3% increase in
lease operations expenses on a BOE basis from $3.98 per BOE in 1998 to $4.11
per BOE in 1999.
Exploration costs decreased 62% from $1.6 million in 1998 to $612,000
in 1999 due primarily to lower seismic costs during the current quarter.
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 40% from
$8.9 million in 1998 to $5.3 million in 1999 due primarily to a 34% decrease
in oil and gas production on a BOE basis during the 1999 quarter. Under the
successful efforts method of accounting, costs of oil and gas properties are
amortized on a unit-of-production method based on estimated proved reserves.
The average depletion rate per BOE was $7.80 in 1999 compared to $8.60 in
1998.
General and administrative expenses decreased 33% from $1.1 million in
1998 to $738,000 in 1999. Beginning in December 1998, the Company implemented
certain cost reduction measures, consisting primarily of personnel layoffs
and salary reductions, in order to reduce overhead and conserve financial
resources. Through these efforts, the Company expects to reduce G&A expenses
in 1999 by approximately 33% on an annualized basis.
Costs of natural gas services decreased 13% from $758,000 in 1998
to $661,000 in 1999 due primarily to a decrease in contract volumes.
INTEREST EXPENSE AND OTHER
Interest expense increased 68% from $477,000 in 1998 to $802,000 in
1999 due primarily to higher average levels of indebtedness on the Credit
Facility, offset in part by lower average interest rates. The average daily
principal balance outstanding on such facility during the first quarter of
1999 was $51.9 million compared to $34.9 million in 1998. The effective
annual interest rate on bank debt, including bank fees, during the 1999
quarter was 7.4% compared to 8.2% in 1998. In addition, capitalized interest
was $150,000 in the 1999 quarter compared to $253,000 in 1998.
During the first quarter of 1999, the Company recorded gains on sales
of property and equipment of $2.2 million, which included a gain of $1.8
million on the sale of the Company's interest in eight non-operated gas well
in Matagorda County, Texas for $5.2 million.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW
The Company's primary financial resource is its oil and gas reserves.
In accordance with the terms of the 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.
12
<PAGE>
The following discussion sets forth the Company's current plans for
capital expenditures in 1999, and the expected capital resources needed to
finance such plans.
CAPITAL EXPENDITURES
Currently, the Company plans to spend approximately $8.4 million on
exploration and development activities during 1999, a significant portion of
which is projected to be spent on the Cotton Valley Exploratory Project in
the North Giddings Block. In January 1999, the Company completed the J. C.
Fazzino Unit #1, a Cotton Valley Pinnacle Reef well in Robertson County,
Texas drilled into one of several reef anomalies identified by a 3-D seismic
survey conducted in 1997. Construction of a gas pipeline and treatment
facility for the well has been completed and arrangements are currently being
made to acidize the well in an attempt to improve initial flow rates. The
Company expects to begin selling gas production from the Fazzino #1 in late
May 1999. In the aggregate, the Company expects to spend approximately $4.2
million in 1999 to complete the well and facilities and to renew and extend
leases in the North Giddings Block, as required. In addition, the Company
plans to spend approximately $1.5 million in 1999 to drill the J. C. Fazzino
Unit #2 as an offset to the Fazzino #1. The remainder of the projected $4.5
million cost to drill and complete the Fazzino #2 will be financed through a
non-recourse vendor financing arrangement which permits the Company to pay
participating vendors for services and materials out of a dedicated
percentage of revenue from the well. Any other wells drilled in this area
within the five-year term of the agreement are also subject to these vendor
financing arrangements.
The Company may increase its planned activities for 1999 depending
upon product prices, the availability of capital resources, and other factors
affecting the economic viability of such activities.
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. 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.
In March 1999, the banks established the borrowing base at $53 million
and provided for an automatic reduction of the borrowing base to $43 million
upon sale of the Company's interests in the Jalmat Field located in Lea
County, New Mexico and further provided for monthly commitment reductions of
$650,000 beginning in July 1999. In April 1999, the Company repaid $11.5
million of indebtedness on the Credit Facility with proceeds from the Jalmat
sale, creating $1.5 million of availability on the revolving loan facility at
that time. The adjusted borrowing base will remain in effect until the next
scheduled borrowing base redetermination in November 1999.
WORKING CAPITAL AND CASH FLOW
During 1999, the Company generated cash flow from operating activities
of $5.2 million, received proceeds from sales of property of $5.7 million,
repaid $1.9 million on the Credit Facility, and spent $3 million on capital
expenditures.
The Company's working capital deficit increased from $15.8 million at
December 31, 1998 to $16 million at March 31, 1999. The Company classified
$17.8 million of its outstanding indebtedness on the Credit Facility as a
current liability based on the required levels of repayments. The Company
also classified the net book value of the Jalmat assets sold in April 1999 as
properties held for resale and, accordingly, reported $4.2 million as a
current asset at March 31, 1999.
13
<PAGE>
ADDITIONAL CAPITAL RESOURCES
The Company believes that the funds available from the sales of
assets, combined with operating cash flow, will be adequate to fund the
required reductions in indebtedness on the Credit Facility and the projected
capital expenditures for 1999. However, because future cash flows and the
availability of borrowings under the Credit Facility are subject to a number
of variables, such as prevailing prices of oil and gas, actual production
from existing and newly-completed wells, the Company's success in developing
and producing new reserves, and the uncertainty with respect to the amount of
funds which may ultimately be required to finance the Company's exploration
program, there can be no assurance that the Company's capital resources will
be sufficient to sustain the Company's exploratory and development activities.
If funds available from asset sales, combined with operating cash
flow, are not sufficient to fund its debt repayments and anticipated levels
of capital expenditures, the Company will be required to seek alternative
forms of capital resources, including the sale of other assets and the
issuance of debt or equity securities. Although the Company believes it will
be able to obtain funds pursuant to one or more of these alternatives, if
needed, management cannot be assured that any such capital resources will be
available to the Company. If additional capital resources are needed, but the
Company is unable to obtain such capital resources on a timely basis, the
Company may not be able to maintain a level of liquidity sufficient to meet
its obligations as they mature or maintain compliance with the required
financial covenants contained in the Credit Facility.
INFORMATION SYSTEMS FOR THE YEAR 2000
Historically, certain computer software systems, as well as certain
hardware containing embedded chip technology, such as microcontrollers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the year
2000. This could result in system failures. The Company relies on its
computer-based management information systems, as well as embedded
technology, to operate instruments and equipment in conducting its day-to-day
business activities. Certain of these computer-based programs and embedded
technology may not have been designed to function properly with respect to
the application of dating systems relating to the year 2000.
In response, the Company has developed a "Year 2000 Plan" and, in
1998, established an internal group to identify and assess potential areas of
risk and to make any required modifications to its computer systems and
equipment used in oil and gas exploration, production, gathering and gas
processing activities. The Year 2000 Plan is comprised of various phases,
including assessment, remediation, testing and contingency plan development.
The Company believes this plan will provide reasonable assurance that its
business activities and facilities will continue to operate safely and
reliably, and without material interruption after 1999.
The Company has completed all phases of the Year 2000 Plan as it
relates to its internal systems and hardware. The Company's inventory of
computer hardware and software is substantially Year 2000 compliant. The
programming modifications for the oil and gas accounting and production
systems were completed by the software vendor in 1997 and were installed and
tested by the Company in November 1998.
The Company has monitor and control equipment with embedded chip
technology which are utilized in production and gas processing operations.
The various systems were reviewed in conjunction with the overall Year 2000
Plan and were found to be Year 2000 compliant based on manufacturers'
representations.
The Company has also undertaken to monitor the compliance efforts of
purchasers, vendors, contractors and other third parties ("Third Party
Providers") with whom it does business and whose computer-based systems
and/or embedded technology equipment interface with those of the Company to
ensure that operations will not be adversely affected by the Year 2000
compliance problems of others. There can be no assurance that there will not
be an adverse effect on the Company if Third Party Providers do not convert
their respective systems in a timely manner and in a way that is compatible
with the
14
<PAGE>
Company's information systems and embedded technology equipment. However,
management believes that ongoing communication with and assessment of the
compliance efforts and status of Third Party Providers will minimize these
risks. Since the Company's operations generally are not dependent on any
single Third Party Provider, the Company is prepared to select Third Party
Providers which are Year 2000 compliant by the fourth quarter of 1999.
To date, the costs to implement the Year 2000 Plan have been nominal
since the primary area for remediation involved software covered by a
maintenance agreement. The Company does not expect to incur any significant
costs during the remainder of 1999 to complete the Year 2000 Plan.
Although the Company anticipates minimal business disruptions as a
result of Year 2000 issues, in the event the computer-based programs and
embedded technology equipment of the Company, or that owned and operated by
Third Party Providers, should fail to function properly, possible
consequences include, but are not limited to, loss of communication links,
inability to produce, process and sell oil and natural gas, loss of electric
power, and inability to automatically process commercial transactions or
engage in similar automated or computerized business activities.
ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
The Company's business is impacted by fluctuations in commodity prices
and interest rates. The following discussion is intended to identify the
nature of these market risks, describe the Company's strategy for managing
such risks, and to quantify the potential affect of market volatility on the
Company's financial condition and results of operations.
OIL AND GAS PRICES
The Company's financial condition, results of operations, and capital
resources are highly dependent upon the prevailing market prices of, and
demand for, oil and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are
beyond the control of the Company. These factors include the level of global
demand for petroleum products, foreign supply of oil and gas, the
establishment of and compliance with production quotas by oil-exporting
countries, weather conditions, the price and availability of alternative
fuels, and overall economic conditions, both foreign and domestic. It is
impossible to predict future oil and gas prices with any degree of certainty.
Sustained weakness in oil and gas prices may adversely affect the Company's
financial condition and results of operations, and may also reduce the amount
of net oil and gas reserves that the Company can produce economically. Any
reduction in reserves, including reductions due to price fluctuations, can
have an adverse affect on the Company's ability to obtain capital for its
exploration and development activities. Similarly, any improvements in oil
and gas prices can have a favorable impact on the Company's financial
condition, results of operations and capital resources. Based on the
Company's volume of oil and gas production for the quarter ended March 31,
1999, a $1 change in the price per barrel of oil and a $.10 change in the
price per Mcf of gas would result in an aggregate change in gross revenues
for such quarter of approximately $584,000.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure
to price fluctuations. While the use of these hedging arrangements limits the
downside risk of price declines, such use may also limit any benefits which
may be derived from price increases. The Company uses various financial
instruments, such as swaps, collars and puts, whereby monthly settlements are
based on differences between the prices specified in the instruments and the
settlement prices of certain futures contracts quoted on the NYMEX or certain
other indices. Generally, when the applicable settlement price is less than
the price specified in the contract, the Company receives a settlement from
the counterparty based on the difference. Similarly, when the applicable
settlement price is higher than the specified price, the Company pays the
counterparty based on the difference. The instruments utilized by the Company
differ from futures contracts in that there is not a contractual obligation
which requires or permits the future physical delivery of the hedged products.
15
<PAGE>
During 1998 and continuing throughout the first quarter of 1999, the
oil and gas industry has operated in a depressed commodity price environment.
Oil prices during the first quarter of 1999 fell to their lowest levels in
history when adjusted for inflation. Although oil prices improved to some
degree in late March 1999, current prices remain substantially lower than
levels achieved in 1997. In November 1997, the Company entered into swap
arrangements on a significant portion of its 1998 oil production and realized
a gain of $8.8 million in 1998 on oil hedges. In addition, the Company hedged
a portion of its 1998 gas production at various times beginning in November
1997 and realized net gains of $1.1 million in 1998 on gas hedges. However,
as prices declined throughout 1998, the prices at which the Company could
hedge its 1999 production were considered by the Company to be too low to
effectively mitigate the downside pricing risks. As a result, the Company's
only open hedge positions as of March 31, 1999 consist of options to sell
400,000 barrels of oil production from April 1999 through June 1999 at a
floor price of $10.00 per barrel. The Company plans to enter into additional
hedging arrangements when and if the market prices for future oil and gas
production improves to favorable levels based on management's analysis of
price expectations.
INTEREST RATES
All of the Company's outstanding indebtedness at March 31, 1999 is
subject to market rates of interest as determined from time to time by the
banks pursuant to the Credit Facility. See "CAPITAL RESOURCES". The Company
may designate borrowings under the Credit Facility as either "Base Rate
Loans" or "Eurodollar Loans." Base Rate Loans bear interest at a fluctuating
rate that is linked to the discount rates established by the Federal Reserve
Board. Eurodollar Loans bear interest at a fluctuating rate that is linked to
LIBOR. Any increases in these interest rates can have an adverse impact on
the Company's results of operations and cash flow. Although various financial
instruments are available to hedge the effects of changes in interest rates,
the Company does not consider the risk to be significant and has not entered
into any interest rate hedging transactions. Based on the Company's
outstanding indebtedness at March 31, 1999 of $53 million, a change in
interest rates of 25 basis points would affect annual interest payments by
approximately $133,000.
16
<PAGE>
PART II. OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------ -----------
<S> <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, 1999.
17
<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 12, 1999 By: /s/ L. Paul Latham
-----------------------------------------
L. Paul Latham
Executive Vice President and Chief
Operating Officer
Date: May 12, 1999 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, 1999 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-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 7,455
<SECURITIES> 0
<RECEIVABLES> 6,055
<ALLOWANCES> 0
<INVENTORY> 1,338
<CURRENT-ASSETS> 19,262
<PP&E> 444,097
<DEPRECIATION> (348,619)
<TOTAL-ASSETS> 114,803
<CURRENT-LIABILITIES> 35,229
<BONDS> 35,250
0
0
<COMMON> 897
<OTHER-SE> 43,427
<TOTAL-LIABILITY-AND-EQUITY> 114,803
<SALES> 7,521
<TOTAL-REVENUES> 8,326
<CGS> 2,704
<TOTAL-COSTS> 10,007
<OTHER-EXPENSES> (2,298)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 802
<INCOME-PRETAX> (185)
<INCOME-TAX> 0
<INCOME-CONTINUING> (185)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (185)
<EPS-PRIMARY> (.02)
<EPS-DILUTED> (.02)
</TABLE>
