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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
/xx/
Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 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.
YES /xx/ NO / /
NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF AUGUST 9, 1999....8,983,549
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CLAYTON WILLIAMS ENERGY, INC.
TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS PAGE
Consolidated Balance Sheets as of June 30, 1999
and December 31, 1998..................................................................... 3
Consolidated Statements of Operations for the three months and six months
ended June 30, 1999 and 1998............................................................. 4
Consolidated Statements of Cash Flows for the six months
ended June 30, 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.................................. 16
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................................................ 18
</TABLE>
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2
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
--------------- ---------------
(UNAUDITED)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents............................................. $ 2,098 $ 1,424
Accounts receivable:
Trade, net.......................................................... 1,322 6,782
Affiliates.......................................................... 1,207 244
Oil and gas sales................................................... 6,899 3,628
Inventory............................................................. 913 1,230
Property held for resale.............................................. - 7,521
Other................................................................. 342 482
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12,781 21,311
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PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method..................... 427,792 424,360
Natural gas gathering and processing systems.......................... 9,752 8,292
Other................................................................. 10,182 10,480
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447,726 443,132
Less accumulated depreciation, depletion and amortization............. (354,023) (343,857)
--------------- ---------------
Property and equipment, net......................................... 93,703 99,275
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OTHER ASSETS............................................................. 62 67
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$ 106,546 $ 120,653
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LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade............................................................... $ 8,351 $ 16,384
Affiliates.......................................................... 71 65
Oil and gas sales................................................... 5,576 3,433
Current maturities of long-term debt.................................. 7,800 15,800
Accrued liabilities and other......................................... 1,211 1,477
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23,009 37,159
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LONG-TERM DEBT........................................................... 31,200 39,100
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STOCKHOLDERS' EQUITY
Preferred stock, par value $.10 per share; authorized - 3,000,000
shares; issued and outstanding - none................................ - -
Common stock, par value $.10 per share; authorized - 15,000,000
shares; issued - 8,977,391 shares in 1999 and 8,937,561
shares in 1998....................................................... 898 894
Additional paid-in capital............................................ 69,920 69,744
Retained deficit...................................................... (18,481) (26,244)
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52,337 44,394
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$ 106,546 $ 120,653
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</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
3
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CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------------------- -------------------------------
1999 1998 1999 1998
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<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales........................... $ 9,909 $ 13,736 $ 17,430 $ 30,565
Natural gas services........................ 871 1,112 1,676 2,048
------------- -------------- ------------- --------------
Total revenues............................ 10,780 14,848 19,106 32,613
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COSTS AND EXPENSES
Lease operations............................ 2,684 3,664 5,388 7,652
Exploration:
Abandonments and impairments.............. 639 5,063 894 5,476
Seismic and other......................... 20 816 377 2,049
Natural gas services........................ 795 951 1,456 1,709
Depreciation, depletion and amortization.... 5,548 8,952 10,840 17,826
General and administrative.................. 1,133 1,095 1,871 2,172
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Total costs and expenses.................. 10,819 20,541 20,826 36,884
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Operating loss............................ (39) (5,693) (1,720) (4,271)
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OTHER INCOME (EXPENSE)
Interest expense............................ (675) (508) (1,477) (985)
Gain on sales of property and equipment..... 8,382 - 10,593 13
Other....................................... 280 5 367 9
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Total other income (expense).............. 7,987 (503) 9,483 (963)
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INCOME (LOSS) BEFORE INCOME TAXES.............. 7,948 (6,196) 7,763 (5,234)
INCOME TAX EXPENSE............................. - - - -
------------- -------------- ------------- --------------
NET INCOME (LOSS).............................. $ 7,948 $ (6,196) $ 7,763 $ (5,234)
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Net income (loss) per common share:
Basic....................................... $ .89 $ (.70) $ .87 $ (.59)
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Diluted..................................... $ .87 $ (.70) $ .86 $ (.59)
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Weighted average common shares outstanding:
Basic....................................... 8,973 8,896 8,964 8,892
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Diluted..................................... 9,107 8,896 9,063 8,892
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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>
SIX MONTHS ENDED
JUNE 30,
------------------------------
1999 1998
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss).......................................................... $ 7,763 $ (5,234)
Adjustments to reconcile net income (loss) to cash provided by
operating activities:
Depreciation, depletion and amortization............................... 10,840 17,826
Exploration costs...................................................... 894 5,476
Gain on sales of property and equipment................................ (10,593) (13)
Other.................................................................. 138 163
Changes in operating working capital:
Accounts receivable.................................................... 1,226 5,623
Accounts payable....................................................... (3,003) (1,190)
Other.................................................................. 196 937
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Net cash provided by operating activities......................... 7,461 23,588
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment........................................ (9,333) (26,550)
Proceeds from sales of property and equipment.............................. 18,404 23
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Net cash provided by (used in) investing activities............... 9,071 (26,527)
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt............................................... - 2,400
Repayments of long-term debt............................................... (15,900) -
Proceeds from sale of common stock......................................... 42 -
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Net cash provided by (used in) financing activities............... (15,858) 2,400
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................ 674 (539)
CASH AND CASH EQUIVALENTS
Beginning of period........................................................ 1,424 2,150
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End of period.............................................................. $ 2,098 $ 1,611
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SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized......................... $ 1,587 $ 993
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</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
5
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CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 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 5).
2. PRESENTATION
The preparation of these consolidated financial statements in conformity
with generally accepted accounting principles requires management of the Company
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
In the opinion of management, the Company's unaudited consolidated
financial statements as of June 30, 1999 and for the interim periods ended June
30, 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:
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<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
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(IN THOUSANDS)
<S> <C> <C>
Secured Bank Credit Facility (matures July 31, 2001).............. $ 39,000 $ 54,900
Less current maturities........................................... (7,800) (15,800)
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$ 31,200 $ 39,100
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6
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The Company's secured bank credit facility (the "Credit Facility")
provides for a revolving loan facility in an amount not to exceed the lesser of
the borrowing base, as established by the banks, or that portion of the
borrowing base determined by the Company to be the elected borrowing limit. 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 June 30, 1999, the borrowing base established by the banks was $43
million and requires monthly commitment reductions of $650,000 beginning in July
1999. The borrowing base will remain in effect until the next scheduled
borrowing base redetermination in November 1999, unless an earlier
redetermination is requested by the Company.
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 June 30, 1999, the Company's indebtedness under the Credit
Facility consisted of $39 million of Eurodollar Loans at a rate of 7.5%.
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 June 30, 1999.
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 six months ended June 30, 1999, the Company issued 23,137 shares of
common stock to one officer in lieu of cash compensation aggregating $128,347.
Subsequent to June 30, 1999, the Company issued an additional 6,158 shares to
the same officer in lieu of cash compensation aggregating $43,574. The amounts
of such compensation are included in general and administrative expense in the
accompanying consolidated financial statements.
5. 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 six month periods ended June 30, 1999 and 1998
are losses totaling $307,000 and net gains totaling $4,989,000 (comprised of
gains of $5,092,000, partially offset by losses of $103,000), 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 $8.3 million.
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 June 30, 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 2001 and is not expected to have a
material effect on the Company's financial condition or operations.
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 June 30, 1999 and
results of operations and cash flows for the periods ended June 30, 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 is required to
maintain or increase its level of drilling activity and achieve comparable or
improved results from such activities. However, weak product prices caused the
Company to suspend its Trend drilling activities in April 1998. In response to
recent improvements in oil and gas prices, the Company initiated a water frac
program in June 1999 in an attempt to accelerate its Trend oil production. The
Company has conducted cyclic water stimulation treatments on 7 wells to date,
and has identified approximately 16 additional wells for stimulation during the
remainder of 1999. Initial daily production rates from the first 5 completed
stimulations have averaged 170 barrels of oil per day, a 300% increase over
pre-stimulation levels. The Company also expects to begin drilling horizontal
infill wells in the Trend during the last half of 1999.
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 and certain
other prospects in Louisiana, the Company has no present plans to incur any
significant capital expenditures in these new areas in 1999 (see "LIQUIDITY AND
CAPITAL RESOURCES - CAPITAL EXPENDITURES"). 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 late May 1999, the Company began selling gas from the J. C. Fazzino
Unit #1, a Cotton Valley Pinnacle Reef discovery in Robertson County, Texas.
To date, the well has produced approximately 620 MMcf of gas, net to the
Company's interest.
9
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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 began drilling J. C. Fazzino Unit #2 in May 1999 in an attempt to
penetrate the core of the reef. The Fazzino #2 was drilled to a total depth of
16,520 feet and, based on gas shows and log analysis, the Company has set
production casing to attempt completion of the well. The Company expects to
begin testing the well in late August 1999. Approximately 67% of the estimated
$4.5 million cost to drill and complete the Fazzino #2 is being 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.
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
interests 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 six 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 June 30, 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
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RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------------------- ---------------------------
1999 1998 1999 1998
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<S> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (MBbls)............................ 476 703 949 1,496
Gas (MMcf)............................. 1,000 1,168 2,110 2,421
MBOE (1)............................... 643 898 1,301 1,900
AVERAGE OIL AND GAS SALES PRICES (2):
Oil ($/Bbl)............................ $ 15.77 $ 16.42 $ 13.51 $ 16.73
Gas ($/Mcf)............................ $ 2.55 $ 2.17 $ 2.03 $ 2.40
OIL AND GAS COSTS ($/BOE PRODUCED):
Lease operating expenses............... $ 4.17 $ 4.08 $ 4.14 $ 4.03
Oil and gas depletion.................. $ 8.38 $ 9.69 $ 8.08 $ 9.12
NET WELLS DRILLED (3):
Exploratory Wells...................... .4 - 1.5 2.5
Developmental Wells.................... - .5 - 4.4
</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 well being drilled or completed at the end of each period.
THREE MONTHS ENDED JUNE 30, 1999 COMPARED TO JUNE 30, 1998
REVENUES
Oil and gas sales decreased 28% from $13.7 million in 1998 to $9.9
million in 1999 due to a 32% decline in oil production and a 14% decline in gas
production. The decline in oil production was caused primarily by the Company's
continued suspension, since April 1998, of its horizontal drilling program in
the Trend in response to low oil prices. Gas production declined due primarily
to the loss of production from two gas properties which were sold in 1999, which
decline was offset in part by new production from the J. C. Fazzino Unit #1.
Since the Fazzino #1 was not placed in production until May 1999, and since the
Company has just recently resumed development activities in the Trend,
production from drilling and completion activities subsequent to June 30, 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.
The Company's average price per barrel of oil declined 4% after giving
effect to a $.22 per barrel loss on hedging activities in the 1999 period as
compared to a $3.62 per barrel gain in the 1998 period. Average gas prices
increased 18% after giving effect to a $.03 per Mcf hedging loss in the 1999
period as compared to a $.09 per Mcf loss in the 1998 period
COSTS AND EXPENSES
Lease operations expenses decreased 27% from $3.7 million in 1998 to $2.7
million in 1999 due primarily to a combination of cost reduction measures
implemented by the Company beginning in the fourth quarter of 1998 and lower
costs attributable to the sale of two gas properties in 1999. Oil and gas
production on a BOE basis decreased 28% during the current quarter, causing a 2%
increase in lease operations expenses on a BOE basis from $4.08 per BOE in 1998
to $4.17 per BOE in 1999.
11
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Exploration costs decreased 89% from $5.9 million in 1998 to $659,000 in
1999 due primarily to substantially lower dry hole costs in the 1999 period as
compared to the 1998 period. 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 39% from $9
million in 1998 to $5.5 million in 1999 due primarily to a 28% decrease in oil
and gas production on a BOE basis during the 1999 quarter and, to a lesser
extent, to a 14% decline in the average depletion rate. Under the successful
efforts method of accounting, costs of oil and gas properties are amortized on a
unit-of-production method based on estimated proved reserves. The decline in the
average depletion rate per BOE from $9.69 in 1998 to $8.38 in 1999 was primarily
due to higher reserve estimates attributable to improved product prices.
General and administrative expenses remained relatively constant from
1998 to 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. The
effects of these efforts were offset in part by the loss of certain overhead
reimbursements associated with the sale of the Company's interests in the Jalmat
Field in April 1999.
INTEREST EXPENSE AND OTHER
Interest expense increased 33% from $508,000 in 1998 to $675,000 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 second quarter of 1999 was $41.4
million compared to $36.2 million in 1998. The effective annual interest rate on
bank debt, including bank fees, during the 1999 quarter was 7.8% compared to
8.1% in 1998. In addition, capitalized interest was $152,000 in the 1999 quarter
compared to $230,000 in 1998.
During the second quarter of 1999, the Company recorded gains on sales of
property and equipment of $8.4 million, which included a gain of $8.3 million on
the sale of the Company's interest in the Jalmat Field location in Lea County,
New Mexico for $12.5 million.
SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO JUNE 30, 1998
REVENUES
Oil and gas sales decreased 43% from $30.6 million in 1998 to $17.4
million in 1999 due primarily to a combination of lower oil and gas production
and lower oil and gas prices. The 37% decline in oil production was caused
primarily by the Company's continued suspension, since April 1998, of its
horizontal drilling program in the Trend in response to low oil prices. Gas
production declined 13% due primarily to the loss of production from two gas
properties which were sold in 1999, which decline was offset in part by new
production from the J. C. Fazzino Unit #1. Since the Fazzino #1 was not placed
in production until May 1999, and since the Company has just recently resumed
development activities in the Trend, production from drilling and completion
activities subsequent to June 30, 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.
The Company's average price per barrel of oil declined 19% after giving
effect to a $.21 per barrel loss on hedging activities in the 1999 period as
compared to a $3.16 per barrel gain in the 1998 period. Average gas prices also
declined 15% after giving effect to a $.05 per Mcf hedging loss in the 1999
period as compared to a $.13 per Mcf gain in the 1998 period.
12
<PAGE>
COSTS AND EXPENSES
Lease operations expenses decreased 30% from $7.7 million in 1998 to $5.4
million in 1999 due primarily to a combination of cost reduction measures
implemented by the Company, beginning in the fourth quarter of 1998, lower costs
attributable to the sale of two gas properties in 1999, and lower production
taxes resulting from significant declines in oil and gas sales. Oil and gas
production on a BOE basis decreased 32% during the current quarter, causing a 3%
increase in lease operations expenses on a BOE basis from $4.03 per BOE in 1998
to $4.14 per BOE in 1999.
Exploration costs decreased 83% from $7.5 million in 1998 to $1.3 million
in 1999 due primarily to a combination of substantially lower dry hole costs,
impairments of unproved properties and seismic costs. 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 39% from $17.8
million in 1998 to $10.8 million in 1999 due primarily to a 32% decrease in oil
and gas production on a BOE basis during the 1999 quarter and, to a lesser
extent, to an 11% decline in the average depletion rate. Under the successful
efforts method of accounting, costs of oil and gas properties are amortized on a
unit-of-production method based on estimated proved reserves. The decline in the
average depletion rate per BOE from $9.12 in 1998 to $8.08 in 1999 was primarily
due to higher reserve estimates during the second quarter of 1999 attributable
to improved product prices.
General and administrative expenses decreased 14% from $2.2 million in
1998 to $1.9 million 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. The effects of these efforts were offset in part by the
loss of certain overhead reimbursements associated with the sale of the
Company's interests in the Jalmat Field in April 1999.
INTEREST EXPENSE AND OTHER
Interest expense increased 52% from $985,000 in 1998 to $1.5 million 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 1999 period was $46.6
million compared to $35.5 million in 1998. The effective annual interest rate on
bank debt, including bank fees, during 1999 was 7.7% compared to 8.2% in 1998.
In addition, capitalized interest was $302,000 in 1999 compared to $484,000 in
1998.
During 1999, the Company recorded gains on sales of property and
equipment of $10.6 million, which included a gain of $8.3 million on the sale of
the Company's interest in the Jalmat Field located in Lea County, New Mexico for
$12.5 million, and a gain of $1.8 million on the sale of the Company's interest
in eight non-operated gas wells in Matagorda County, Texas for $5.2 million.
13
<PAGE>
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.
In March 1999, the banks established the Credit Facility 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. The
adjusted borrowing base will remain in effect until the next scheduled borrowing
base redetermination in November 1999 unless an earlier redetermination is
requested by the Company.
Although the Company had $4 million available on the Credit Facility at
June 30, 1999, the monthly commitment reductions of $650,000 beginning in July
1999 will reduce the borrowing base to $39.8 million before the next
redetermination. Accordingly, the Company will be required to finance most of
its remaining capital expenditures for 1999 out of internally generated cash
flow.
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
The Company has increased the amount it plans to spend in 1999 on
exploration and development activities from $8.4 million to $16.9 million.
Approximately 75% of the increase relates to the Company's plan to resume
development activities in the Trend.
In response to improving product prices, the Company has initiated a
water frac program in an attempt to accelerate its Trend oil production. To
date, the Company has conducted cyclic water stimulations on 7 wells and plans
to stimulate approximately 16 additional wells during the remainder of 1999. In
addition, the Company presently plans to drill two infill horizontal wells
during the last half of 1999. In the aggregate, the Company plans to spend
approximately $7.6 million on Trend development and leasing activities, of which
$1.5 million has been incurred through June 30, 1999.
The Company also plans to spend approximately $5.3 million on exploration
and leasing activities on the Cotton Valley Exploratory Project in the North
Giddings Field, of which $4.1 million has been incurred through June 30, 1999.
The Company has drilled the J. C. Fazzino Unit #1 and has completed construction
of a gas pipeline and treatment facility. The Fazzino #1 began selling gas
production in May 1999 and has produced approximately 620 MMcf of gas to date,
net to the Company's interest. The Company has also drilled the J. C. Fazzino
Unit #2 and expects to complete the well in late August 1999. The Fazzino #2 was
drilled pursuant to 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.
14
<PAGE>
The remaining $4 million of estimated 1999 capital expenditures relate to
seismic, leasing and drilling costs on various exploratory prospects, primarily
in Louisiana, and to development drilling costs on existing prospects in the
Texas Gulf Coast region.
The Company may increase or decrease its planned activities for 1999
depending upon drilling results, product prices, the availability of capital
resources, and other factors affecting the economic viability of such
activities.
CAPITAL RESOURCES
During the first six months of 1999, the Company generated cash flow from
operating activities of $7.5 million and received proceeds from sales of
property and equipment of $18.4 million. During the same period, the Company
repaid $15.9 million on the Credit Facility and spent $9.3 million on capital
expenditures. At June 30, 1999, the Company had $4 million available on the
Credit Facility, as compared to $2.1 million at December 31, 1998.
The Company's working capital deficit decreased from $15.8 million at
December 31, 1998 to $10.2 million at June 30, 1999. The Company classified $7.8
million of its outstanding indebtedness on the Credit Facility at June 30, 1999
as a current liability based on the required levels of repayments, as compared
to $15.8 million at December 31, 1998.
During 1998 and continuing throughout the first quarter of 1999, the oil
and gas industry operated in a depressed commodity price environment. The
effects of low product prices on the Company's capital resources were pervasive,
having contributed significantly to declines in operating cash flow and funds
available on the Credit Facility. Based on recent improvements in product
prices, the Company anticipates a corresponding increase in its operating cash
flow during the last half of 1999. Accordingly, the Company plans to utilize the
additional cash flow to finance a higher level of capital expenditures in 1999.
The Company believes that its operating cash flow, along with any funds which
may be available on the Credit Facility, will be adequate to fund 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 the Company's operating cash flow, along with any funds which may be
available on the Credit Facility, are not sufficient to fund its anticipated
levels of capital expenditures, the Company may be required to seek alternative
forms of capital resources, including the sale of 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.
15
<PAGE>
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 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-
16
<PAGE>
exporting countries, weather conditions, the price and availability of
alternative fuels, and overall economic conditions, both foreign and
domestic. It is impossible to predict future oil and gas prices with any
degree of certainty. Sustained weakness in oil and gas prices may adversely
affect the Company's financial condition and results of operations, and may
also reduce the amount of net oil and gas reserves that the Company can
produce economically. Any reduction in reserves, including reductions due to
price fluctuations, can have an adverse affect on the Company's ability to
obtain capital for its exploration and development activities. Similarly, any
improvements in oil and gas prices can have a favorable impact on the
Company's financial condition, results of operations and capital resources.
Based on the Company's volume of oil and gas production for the six months
ended June 30, 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 of approximately $1.2 million.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure to
price fluctuations. While the use of these hedging arrangements limits the
downside risk of price declines, such use may also limit any benefits which may
be derived from price increases. The Company uses various financial instruments,
such as swaps, 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.
During 1998 and continuing throughout the first half 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 and gas prices have improved significantly
since April 1999, the commodity futures market remains somewhat volatile and
continues to reflect the uncertainties that exist regarding near-term supply of
and demand for oil and gas. 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. As prices declined
throughout 1998, the prices at which the Company could hedge its 1999 production
were generally considered by the Company to be too low to effectively mitigate
the downside pricing risks. However, in December 1998, the Company purchased a
floor on 800,000 barrels of oil production from January 1999 through June 1999
at a price of $10.00 per barrel and hedged an aggregate of 750,000 MMBtu of gas
production from January 1999 through June 1999. The gas hedge was subsequently
terminated at an aggregate loss of $102,000. The Company does not have any open
hedge positions as of June 30, 1999. The Company plans to enter into additional
hedging arrangements when and if the market prices for future oil and gas
production improve to favorable levels based on management's analysis of price
expectations.
INTEREST RATES
All of the Company's outstanding indebtedness at June 30, 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 June 30, 1999 of $39 million, a change in interest rates of 25
basis points would affect annual interest payments by approximately $98,000.
17
<PAGE>
PART II. OTHER INFORMATION
ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K
EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
27 Financial Data Schedule
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended June 30,
1999.
18
<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: August 12, 1999 By: /S/ L. Paul Latham
-----------------------------------
L. Paul Latham
Executive Vice President and Chief
Operating Officer
Date: August 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 JUNE
30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<CASH> 2,098
<SECURITIES> 0
<RECEIVABLES> 9,428
<ALLOWANCES> 0
<INVENTORY> 913
<CURRENT-ASSETS> 12,781
<PP&E> 447,726
<DEPRECIATION> (354,023)
<TOTAL-ASSETS> 106,546
<CURRENT-LIABILITIES> 23,009
<BONDS> 31,200
0
0
<COMMON> 898
<OTHER-SE> 51,439
<TOTAL-LIABILITY-AND-EQUITY> 106,546
<SALES> 17,430
<TOTAL-REVENUES> 19,106
<CGS> 5,388
<TOTAL-COSTS> 20,826
<OTHER-EXPENSES> (10,960)<F1>
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,477
<INCOME-PRETAX> 7,763
<INCOME-TAX> 0
<INCOME-CONTINUING> 7,763
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 7,763
<EPS-BASIC> .87
<EPS-DILUTED> .86
<FN>
<F1>INCLUDES $10.1 MILLION GAIN ON SALES OF ASSETS.
</FN>
</TABLE>
