<PAGE>
1,250,000 SHARES
[LOGO]
COMMON STOCK
All of the 1,250,000 shares of Common Stock offered hereby are being sold by
Clayton Williams Energy, Inc. (the "Company"). The Underwriters are reserving an
aggregate of 200,000 shares of Common Stock to be offered at the Price to Public
set forth below to Clayton Williams Partnership, Ltd., a limited partnership
controlled by Clayton W. Williams, Jr., Chairman of the Board, President and
Chief Executive Officer of the Company.
The Common Stock is quoted on the Nasdaq National Market under the symbol
"CWEI." The last reported sale price of the Common Stock on November 13, 1996,
as reported by the Nasdaq National Market, was $13 1/4 per share. See "Price
Range of Common Stock."
FOR A DISCUSSION OF CERTAIN MATERIAL FACTORS THAT SHOULD BE CONSIDERED IN
CONNECTION WITH AN INVESTMENT IN THE COMMON STOCK, SEE "RISK FACTORS" COMMENCING
ON PAGE 7 HEREOF.
-----------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION NOR HAS THE SECURITIES AND EXCHANGE
COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED
UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS (1) COMPANY (2)
<S> <C> <C> <C>
Per Share.............................. $13.00 $0.85 $12.15
Total (3).............................. $16,250,000 $1,062,500 $15,187,500
</TABLE>
(1) The Company has agreed to indemnify the Underwriters against certain civil
liabilities, including certain liabilities under the Securities Act of 1933,
as amended. See "Underwriting."
(2) Before deducting offering expenses estimated to be approximately $270,000
payable by the Company.
(3) The Company has granted to the Underwriters a 30-day option to purchase up
to 187,500 additional shares of Common Stock solely to cover
over-allotments, if any, on the same terms and conditions as the shares
offered hereby. If such option is exercised in full, the total Price to
Public, Underwriting Discounts and Commissions and Proceeds to Company will
be $18,687,500, $1,221,875 and $17,465,625, respectively. See
"Underwriting."
-------------------
The shares of Common Stock are offered by the several Underwriters named
herein, subject to receipt and acceptance by them and subject to their right to
reject any order in whole or in part. It is expected that delivery of such
shares will be at the offices of Rodman & Renshaw, Inc., New York, New York on
or about November 19, 1996.
-------------------
RODMAN & RENSHAW, INC. HANIFEN, IMHOFF INC.
The date of this Prospectus is November 13, 1996.
<PAGE>
[PICTURE DEPICTING THE COMPANY'S METHOD
OF DRILLING WELLS IN THE TREND]
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NASDAQ NATIONAL MARKET, IN THE
OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME. IN CONNECTION WITH THIS OFFERING, CERTAIN UNDERWRITERS
AND SELLING GROUP MEMBERS (IF ANY) OR THEIR RESPECTIVE AFFILIATES MAY ENGAGE IN
PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON THE NASDAQ NATIONAL
MARKET IN ACCORDANCE WITH RULE 10B-6A UNDER THE SECURITIES EXCHANGE ACT OF 1934.
SEE "UNDERWRITING."
<PAGE>
PROSPECTUS SUMMARY
THE FOLLOWING SUMMARY SHOULD BE READ IN CONJUNCTION WITH, AND IS QUALIFIED
IN ITS ENTIRETY BY, THE MORE DETAILED INFORMATION AND CONSOLIDATED FINANCIAL
STATEMENTS (INCLUDING THE NOTES THERETO) APPEARING ELSEWHERE IN THIS PROSPECTUS
AND INCORPORATED HEREIN BY REFERENCE. THE TERM "COMPANY" REFERS TO CLAYTON
WILLIAMS ENERGY, INC., ITS SUBSIDIARIES AND ITS PREDECESSORS, UNLESS THE CONTEXT
REQUIRES OTHERWISE. UNLESS OTHERWISE INDICATED, ALL INFORMATION IN THIS
PROSPECTUS ASSUMES THAT THE UNDERWRITERS' OVER-ALLOTMENT OPTION WILL NOT BE
EXERCISED. SEE "GLOSSARY OF TERMS" FOR DEFINITIONS OF CERTAIN TERMS RELATING TO
THE OIL AND GAS INDUSTRY USED IN THIS PROSPECTUS. INVESTORS SHOULD CAREFULLY
CONSIDER THE INFORMATION SET FORTH IN "RISK FACTORS" BEGINNING ON PAGE 7.
THE COMPANY
GENERAL
Clayton Williams Energy, Inc. is primarily engaged in the exploration,
development and production of oil and natural gas, and to a lesser extent, in
the gathering and marketing of natural gas. Since 1988, the Company and its
predecessors have concentrated their drilling activities primarily in the
Cretaceous Trend (the "Trend"), which extends from South Texas through East
Texas, Louisiana and other southern states and includes the Austin Chalk
formation. The Company also has operations in the Jalmat Field located in
southeastern New Mexico and in the Texas Gulf Coast. As of June 30, 1996, the
Company had estimated proved reserves totaling 6,844 Mbbls of oil and 37.7 Bcf
of gas with a PV-10 Value of approximately $100.3 million as estimated by
Williamson Petroleum Consultants, Inc. (the "Independent Engineers"). At June
30, 1996, the Company held interests in 455 gross (337.1 net) oil and gas wells
and owned leasehold interests in approximately 191,289 gross (129,632 net)
undeveloped acres.
BUSINESS STRATEGY
The Company's business strategy is to increase reserves and production
through exploration and development of its oil and gas properties, concentrating
its efforts in the Trend. The Company has operated in the Trend for 20 years and
drilled or participated in the drilling of 634 gross vertical and horizontal
wells through June 30, 1996. Development of the Austin Chalk formation, which is
characterized by fractured carbonate reservoirs, has been enhanced by advances
in horizontal drilling and completion technologies since the early 1990's. These
advances have provided the Company with the opportunity to develop new reserves
and to generate more attractive economic returns in the Austin Chalk formation.
The Company believes that it is one of the leaders in horizontal drilling in the
Trend. From January 1, 1990 through June 30, 1996, the Company drilled or
participated in 223 gross (175.2 net) horizontal wells in the Trend.
The Company's operational focus for the remainder of 1996 and 1997 will be
the continued development of a lease block (the "North Giddings Block") which
the Company has assembled in the updip area of the Giddings Field in east
central Texas. The Company has accumulated approximately 109,000 net acres in
the North Giddings Block and is continuing to lease acreage in this area. The
North Giddings Block is located in the northern area of the Giddings Field in
Burleson, Robertson and Milam Counties, Texas, where the Austin Chalk formation
is encountered at depths ranging from 5,500 feet to 7,000 feet.
During the six months ended June 30, 1996, the Company added 1,718 MBOE of
estimated proved reserves through extensions and discoveries primarily in the
North Giddings Block. Reserve additions for the first six months of 1996 were
110% of production for the same period, while production for such period was
approximately the same on an MBOE basis as in the first six months of 1995. As
of June 30, 1996, the Company had 61.2 producing net wells in the North Giddings
Block and 76 additional drilling locations, of which seven are locations to
which proved undeveloped reserves are attributed by the Independent Engineers.
3
<PAGE>
The Company believes, based on initial 2-D seismic surveys, that a portion
of the North Giddings Block is on-trend with the Cotton Valley pinnacle reef
play. Successful wells have been drilled in the Cotton Valley formation
approximately 24 miles northeast of the North Giddings Block. The Company has
planned an exploration project in three phases (the "Cotton Valley Exploratory
Project") to explore for potential reserves in this formation. The first phase
is a proprietary 3-D seismic survey covering portions of the North Giddings
Block. The second phase is the interpretation of the seismic data to delineate
any drilling opportunities in the Cotton Valley formation. The third phase would
be the exploratory drilling of any delineated prospects. To date, the Company
has committed to conduct a seismic survey covering approximately 20,000 acres in
Robertson County at a cost of approximately $3.1 million, including
interpretation. The Company anticipates that the survey will be completed during
the first quarter of 1997 and that the resulting data will be interpreted during
the second quarter of 1997. The Company may conduct additional surveys covering
other portions of the North Giddings Block. The Company's ability to drill any
delineated prospects will depend upon the availability of capital and other
factors that may be beyond its control. The Company's current policy is to limit
its annual Cotton Valley Exploratory Project expenditures to not more than 25%
of its planned annual capital expenditures. However, the Company may modify this
policy depending upon certain factors, including the Company's financial
position, exploratory drilling success, technological advances, drilling
activities conducted by third parties and current and anticipated product
prices. See "Risk Factors--Liquidity and Capital Resources" and "--Risk of
Exploratory Activities."
The principal executive offices of the Company are located at Six Desta
Drive, Suite 6500, Midland, Texas 79705, and its telephone number at such
offices is (915) 682-6324.
THE OFFERING
<TABLE>
<S> <C>
Common Stock Offered by the Company......... 1,250,000 shares
Common Stock to be Outstanding After the
Offering (1).............................. 8,748,216 shares
Use of Proceeds............................. To provide funds for the Company's 1997
planned capital expenditure program and one or
more 3-D seismic surveys as part of the Cotton
Valley Exploratory Project. See "Use of
Proceeds."
Nasdaq National Market Symbol............... "CWEI"
</TABLE>
- ------------------------
(1) Does not include options to purchase 270,048 shares of Common Stock which
have been granted under the Company's stock option plans.
4
<PAGE>
SUMMARY FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table sets forth summary consolidated financial data of the
Company for each of the three years ended December 31, 1995, which have been
derived from the Company's audited Consolidated Financial Statements. The
financial data for the year ended December 31, 1993 include the historical
results of the Company and its predecessors, which were consolidated in 1993
(the "Consolidation"). The financial data of the Company for the nine months
ended September 30, 1995 and 1996 have been derived from the Company's unaudited
interim Consolidated Financial Statements, which in the opinion of management of
the Company, have been prepared on the same basis as the annual Consolidated
Financial Statements and include all adjustments (consisting of only normal
recurring adjustments) necessary for a fair presentation of the financial data
for such periods. The information in this table should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements and the notes thereto
included elsewhere herein. The results for the nine month period ended September
30, 1996 are not necessarily indicative of results for the full year.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------- ----------------------
1993 1994 1995 1995 1996
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Total revenues........................ $ 59,595 $ 49,485 $ 49,271 $ 37,627 $ 45,050
---------- ---------- ---------- ---------- ----------
Costs and expenses:
Lease operations.................... 12,788 12,775 13,533 10,231 10,808
Exploration......................... 6,198 7,139 1,555 863 515
Natural gas services................ 2,518 3,510 3,714 3,038 2,363
Depreciation, depletion and
amortization...................... 26,751 25,248 25,110 20,011 17,743
Impairment of property and
equipment......................... -- -- 10,259 -- 1,186
General and administrative.......... 6,876 5,659 3,708 2,739 2,399
---------- ---------- ---------- ---------- ----------
Total costs and expenses.......... 55,131 54,331 57,879 36,882 35,014
---------- ---------- ---------- ---------- ----------
Operating income (loss)........... 4,464 (4,846) (8,608) 745 10,036
Interest expense...................... 4,003 4,461 5,493 4,224 2,783
Other income (expense) (1)............ 149 759 6,022 6,198 60
---------- ---------- ---------- ---------- ----------
Income (loss) before income taxes..... 610 (8,548) (8,079) 2,719 7,313
Income taxes (2)...................... 207 -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income (loss)..................... $ 403 $ (8,548) $ (8,079) $ 2,719 $ 7,313
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Net income (loss) per common share.... $ 0.09 $ (1.50) $ (1.31) $ 0.47 $ 0.96
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Weighted average common shares
outstanding......................... 4,700 5,700 6,165 5,750 7,588
OTHER DATA:
Net cash provided by operating
activities........................ $ 29,716 $ 23,672 $ 24,201 $ 19,688 $ 30,047
EBITDAX (3)......................... 37,413 27,541 28,316 21,619 29,480
EBITDAX per share................... 7.96 4.83 4.59 3.76 3.89
</TABLE>
<TABLE>
<CAPTION>
AT SEPTEMBER 30, 1996
----------------------------
ACTUAL AS ADJUSTED (4)
-------- ------------------
<S> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)...................................... $ (5,559) $ (5,559)
Total assets................................................... 95,647 95,647
Long-term debt................................................. 36,522 21,604
Stockholders' equity........................................... 42,669 57,587
</TABLE>
- ------------------------------
(1) The 1995 periods include a $6.0 million non-recurring gain on sale of the
Company's two principal gas gathering and processing systems.
(2) Prior to the Consolidation, income taxes were computed at the applicable
federal statutory rate.
(3) EBITDAX refers to earnings before income taxes, interest expense,
depreciation, depletion and amortization, impairment of property and
equipment, exploration costs, and other income (expense). EBITDAX is a
financial measure commonly used in the Company's industry and should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity.
(4) As adjusted to reflect receipt by the Company of estimated net proceeds from
the issuance of 1,250,000 shares of Common Stock and the application of such
proceeds. See "Use of Proceeds" and "Capitalization."
5
<PAGE>
SUMMARY OIL AND GAS RESERVE DATA
The following table sets forth summary information concerning the Company's
estimated proved oil and gas reserves as of June 30, 1996, based on a report
prepared by the Independent Engineers, a summary of which is included as Annex A
to this Prospectus. All calculations have been made in accordance with the rules
and regulations of the Securities and Exchange Commission (the "Commission").
See "Risk Factors--Uncertainty of Estimates of Reserves and Future Net
Revenues."
<TABLE>
<CAPTION>
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
----------- ------------- ----------
<S> <C> <C> <C>
Estimated Proved Reserves:
Oil (Mbbls)............................................................... 6,022 822 6,844
Gas (Mmcf)................................................................ 31,440 6,257 37,697
MBOE...................................................................... 11,262 1,865 13,127
Present value of estimated future net revenues,
discounted at 10% (in thousands)........................................ $ 93,022 $ 7,319 $ 100,341
</TABLE>
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (Mbbls).................................................... 1,881 1,709 1,831 1,376 1,601
Gas (Mmcf)..................................................... 10,364 8,369 6,845 5,377 4,183
Total (MBOE)................................................... 3,608 3,104 2,972 2,272 2,298
AVERAGE OIL AND GAS SALES PRICES(1):
Oil ($/Bbl).................................................... $ 17.41 $ 15.72 $ 17.35 $ 17.40 $ 19.76
Gas ($/Mcf).................................................... $ 2.15 $ 1.98 $ 1.77 $ 1.70 $ 2.48
OPERATING COSTS AND EXPENSES ($/BOE PRODUCED):
Lease operations............................................... $ 3.54 $ 4.12 $ 4.55 $ 4.50 $ 4.70
Oil and gas depletion.......................................... $ 7.03 $ 7.81 $ 8.16 $ 8.51 $ 7.46
General and administrative..................................... $ 1.90 $ 1.82 $ 1.24 $ 1.21 $ 1.04
NET WELLS DRILLED:
Horizontal wells............................................... 27.6 16.2 23.5 18.5 17.2
Vertical wells................................................. 0.1 3.6 -- -- 1.1
</TABLE>
- ------------------------
(1) Includes effects of hedging transactions. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Hedging
Transactions."
6
<PAGE>
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
The discussion in this Prospectus contains forward-looking statements that
involve risks and uncertainties. The Company's actual results could differ
significantly from those discussed herein. Factors that could cause or
contribute to such differences include, but are not limited to, those discussed
in "Risk Factors," "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and "Business and Properties," as well as those
discussed elsewhere in this Prospectus. Statements contained in this Prospectus
that are not historical facts are forward-looking statements that are subject to
the safe harbor created by the Private Securities Litigation Reform Act of 1995.
RISK FACTORS
In evaluating an investment in the Common Stock being offered hereby,
prospective investors should consider carefully, among other things, the
following risk factors.
VOLATILITY OF OIL AND GAS PRICES
The Company's revenues, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
gas. Prices for oil and gas are subject to wide fluctuation in
response to relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and a variety of additional factors that are beyond the
control of the Company. These factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels, political conditions in the Middle
East, foreign supply of oil and gas, the price of foreign imports and overall
economic conditions. In recent years, oil and gas prices have been depressed by
excess domestic and imported supplies. Prices have risen recently, but there can
be no assurance that such price levels will be sustained. It is impossible to
predict future oil and gas price movements with any certainty. Declines in oil
and gas prices may adversely affect the Company's financial condition, liquidity
and results of operations. Lower oil and gas prices may also reduce the amount
of the Company's oil and gas reserves that can be produced economically.
Moreover, any fall in the prices of oil and gas materially below their current
levels may have a material adverse affect on the Company's ability to repay
outstanding amounts under its bank credit facility (the "Credit Facility"). With
the objective of reducing price risk, the Company enters into hedging
transactions from time to time with respect to a portion of its expected future
production. There can be no assurance, however, that such hedging transactions
will reduce risk or mitigate the effect of any substantial or extended decline
in oil or gas prices. Any substantial or extended decline in the prices of oil
or gas would have a material adverse affect on the Company's financial condition
and results of operations. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
ABILITY TO REPLACE SHORT-LIVED RESERVES
As is customary in the oil and gas exploration and production industry, the
Company's future success depends upon its ability to find, develop and acquire
additional oil and gas reserves that are economically recoverable. The Company's
producing properties in the Trend are characterized by a high initial production
rate, followed by a steep decline in production. As a result, the Company must
locate and develop or acquire new oil and gas reserves to replace those being
depleted by production. Without successful drilling and exploration or
acquisition activities, the Company's reserves and revenues will decline
rapidly. No assurance can be given that the Company will be successful in
extending its reserve life, which is currently shorter than the average in the
industry. The Company's current strategy includes increasing its reserve base
through drilling activities on existing properties. There can be no assurance,
however, that the Company's exploration and development projects will result in
significant additional reserves or that the Company will have continuing success
drilling productive wells at economically viable costs. Furthermore, while the
Company's revenues may increase if prevailing oil and gas prices increase
significantly, the Company's finding costs for additional reserves could also
increase.
7
<PAGE>
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
This Prospectus contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based upon reports
prepared by the Independent Engineers. Such reports rely upon various
assumptions, including assumptions required by the Commission as to oil and gas
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. For a description of assumptions utilized by the
Independent Engineers in preparing such estimate, see Annex A. The process of
estimating oil and gas reserves is complex, requiring significant decisions and
assumptions in the evaluation of available geological, geophysical, engineering
and economic data for each reservoir. As a result, such estimates are inherently
imprecise. Actual future production, oil and gas prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable oil
and gas reserves may vary substantially. Any significant variance in these
assumptions could materially affect the estimated quantity and value of reserves
set forth in this Prospectus. In addition, the Company's reserves may be subject
to downward or upward revision based upon production history, results of future
development and exploration, prevailing oil and gas prices and other factors,
many of which are beyond the Company's control. Actual production, revenues,
taxes, development expenditures and operating expenses with respect to the
Company's reserves will likely vary from the estimates used, and such variances
may be material.
Approximately 14% of the Company's total proved reserves at June 30, 1996
were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. The reserve data set forth in the Independent Engineers' report as
of June 30, 1996 assumes, based on the Company's estimates, that aggregate
capital expenditures by the Company of approximately $8.3 million through 1998
will be required to develop such reserves. Although cost and reserve estimates
attributable to the Company's oil and gas reserves have been prepared in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated. See "Business and Properties--Reserves."
The present value of future net revenues referred to in this Prospectus
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net revenues
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net revenues also will be affected by changes in
consumption and changes in governmental regulations or taxation. The timing of
actual future net revenues from proved reserves, and thus their actual present
value, will be affected by the timing of both the production and the incurrence
of expenses in connection with development and production of oil and gas
properties. In addition, the 10% discount factor, which is required by the
Commission to be used in calculating discounted future net revenues for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
the Company or the oil and gas industry in general.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary financial resource is its proved developed oil and gas
reserves. In accordance with the terms of the Credit Facility, the banks
establish a borrowing base from time to time against which the Company may
borrow funds as needed to supplement cash flow from operations as a source of
financing its capital expenditure program. The Company's readily available
resources at any point in time are limited to the excess of the borrowing base
over the then-outstanding level of indebtedness. The borrowing base is currently
subject to a monthly commitment reduction of $1 million. At September 30, 1996,
the Company had $12.5 million of availability under the Credit Facility.
8
<PAGE>
In response to favorable oil prices and drilling results, the Company
intends to accelerate its drilling program by contracting for a third drilling
rig beginning in December 1996. At this increased level of drilling activity,
the Company plans to incur capital expenditures of approximately $42 million
during 1997. In addition, the Company has committed to spend approximately $3.1
million in 1997 to conduct and evaluate a proprietary 3-D seismic survey
covering a portion of its acreage in connection with the Cotton Valley
Exploratory Project and may conduct additional surveys covering other portions
of the North Giddings Block. At these levels of expenditures, the Company
believes that proceeds from this Offering, cash flow from operations and funds
available under the Credit Facility will be sufficient in the aggregate to fund
its planned capital and exploratory expenditures. However, because future cash
flows and the availability of borrowings are subject to a number of variables,
such as the level of production from existing wells, the Company's success in
locating and producing new reserves, prevailing prices of oil and gas, and the
uncertainty with respect to the amount of funds which may ultimately be required
to finance the Cotton Valley Exploratory Project, there can be no assurance that
the Company's capital resources will be sufficient to sustain the Company's
exploratory and development activities, even with the proceeds of this Offering.
In the event additional financing is required to fund the Company's growth, no
assurances can be given as to the availability or terms of such financing. See
"--Risk of Exploratory Activities" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources"
and the Consolidated Financial Statements.
RISK OF EXPLORATORY ACTIVITIES
The Company intends to devote significant resources in 1997 in initiating
the Cotton Valley Exploratory Project. See "Business and Properties--Cotton
Valley Exploratory Project." The lack of geographic proximity of the North
Giddings Block to production from depths to be covered by the 3-D seismic survey
increases the risk that no drillable prospects may be generated as a result of
such activities. Any wells to be drilled as a result of such efforts or any
other exploratory wells may be materially more expensive and involve a higher
degree of risk than the Company's traditional drilling activities. Exploratory
drilling is subject to numerous risks, including the risk that no commercially
productive oil and natural gas reservoirs will be encountered. The cost of
drilling, completing and operating wells is often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected formation and drilling conditions, pressure or
other irregularities in formations, equipment failures or accidents, as well as
compliance with governmental requirements and shortages or delays in the
delivery of equipment. In addition, exploratory drilling using 3-D seismic
surveys requires greater pre-drilling expenditures than alternative forms of
traditional drilling strategies. Because the Company uses the successful efforts
method of accounting, the costs incurred in connection with the seismic portion
of the Cotton Valley Exploratory Project will be expensed when incurred.
Accordingly, the Company's results of operations will be adversely affected by
the incurrence of such costs.
The Company will not conduct any exploratory drilling with respect to the
Cotton Valley Exploratory Project until the 3-D seismic data is evaluated. If
exploratory drilling appears advisable, the Company may drill one or more wells
without third party participation. If the Company determines that third party
participation is advisable to limit its financial risk, such participation will
reduce the Company's interest in any reserves discovered. In addition, the
Company's ability to bear the financial risks of such exploratory activities is
subject to a number of factors, some of which, such as prices for oil and gas,
are beyond the Company's control. Therefore, no assurance can be given as to the
extent, if any, that the Company will conduct exploratory drilling activities.
See "--Liquidity and Capital Resources".
ACTIVITIES OF AFFILIATES
As a result of the Consolidation of various entities controlled by Clayton
W. Williams, Jr. (the "Predecessors") into the Company contemporaneously with
its initial public offering, the Company succeeded to all the oil and gas
exploration and development operations of the Predecessors, except for certain
producing and non-producing oil and gas properties which were not contributed to
the Company
9
<PAGE>
(the "Excluded Properties"). The Excluded Properties were excluded because such
properties were either outside of the principal geographic areas in which it was
proposed that the Company would conduct its activities or did not offer
significant opportunity for future exploration and development activities. Mr.
Williams and certain entities affiliated with him (collectively, the "Williams
Entities") continue to own the Excluded Properties and may conduct activities on
such properties. Such activities will generally be limited to operations on
properties that are currently producing oil and gas and on certain undeveloped
acreage held by production. The selection of the Excluded Properties and the
nature of the arrangements in connection therewith were determined by Mr.
Williams and the Predecessors, each of which was an affiliate of Mr. Williams.
Accordingly, they are not the result of arm's-length negotiations between
independent parties. The Company has been granted a right of first refusal to
acquire undeveloped acreage not held by production and certain mineral interests
owned by the Williams Entities at such time as they propose to conduct drilling
activities thereon or receive an offer from a third party to acquire such
acreage or mineral interests which the Williams Entities intend to accept. Any
decision by the Company to exercise its right of first refusal with respect to
such acreage or mineral interest will be subject to approval by a majority of
the Company's independent directors.
Whether a director is independent with respect to a particular transaction
would be determined at the time of the transaction in light of all the facts and
circumstances. William P. Clements and Robert L. Parker are the only directors
of the Company who are independent with respect to a determination by the
Company to exercise its right of first refusal with respect to the Excluded
Properties consisting of acreage or mineral interests.
If the Company does not exercise its right of first refusal with respect to
any such acreage or mineral interests, the Williams Entities may elect to
conduct drilling operations thereon or accept a third party offer for such
acreage or mineral interests, as the case may be. The Williams Entities have
agreed that, so long as Mr. Williams serves as an officer or director of the
Company and for one year thereafter (except in the case of the involuntary
termination of Mr. Williams' employment), they will conduct all of their future
domestic and international oil and gas exploration, development and acquisition
activities and gas gathering and marketing activities through the Company,
except activities relating to the Excluded Properties.
CONTINUING TRANSACTIONS WITH CERTAIN AFFILIATES
The Company has entered into certain agreements in order to define its
ongoing relationships with Mr. Williams and the Williams Entities. The primary
agreement entered into by the Company and the Williams Entities is a service
agreement with respect to tax, legal, payroll and benefits, aircraft usage, and
lease operating and technical services with respect to the Excluded Properties.
The agreement is not the result of arms-length negotiations between independent
parties.
The Company also has a policy pursuant to which it may offer its employees,
including its officers, the opportunity to participate with the Company in
acquisition or drilling activities on prospects acquired or drilled by the
Company. Although this policy has only resulted in one such opportunity being
presented since the Company's formation, the policy may present opportunities
for conflicts of interest. See "Certain Transactions and Relationships--Certain
Contractual Arrangements--Acquisition of Oil and Gas Interests."
Additionally, the Company has in the past and may in the future enter into
other significant transactions and agreements incident to its business with the
Williams Entities. See "Certain Transactions and Relationships". Any future
material transactions between the Company and its directors, officers, principal
stockholders or other affiliates will be subject to approval by a majority of
the Company's independent and disinterested directors. The Company's Board of
Directors will be advised in advance of any such proposed transactions that are
material to the Company and will utilize such procedures in evaluating their
terms as are appropriate in light of the fiduciary duties of the Board of
Directors under Delaware law. Depending on the size and nature of the proposed
transaction, in any such review the Board
10
<PAGE>
may utilize outside experts or consultants, including independent legal counsel,
secure appraisals or other market comparisons, refer to generally available
statistics or prices or take such other actions as are appropriate under the
circumstances. Although the Company intends that the terms of any such future
transactions and agreements will be at least as favorable to the Company as
those that could be obtained from unaffiliated third parties, no assurance can
be given that this will be the case.
DEPENDENCE ON KEY PERSONNEL
The Company believes that its success will be highly dependent upon its
continued ability to attract and retain skilled managers, including Mr.
Williams. The Company has not entered into employment agreements with any of its
executive officers. Although Mr. Williams devotes the majority of his time to
the Company, he devotes a portion of his time to business ventures in which the
Company does not have an interest. The Company does not maintain key man life
insurance policies on any of its employees.
CONTROL OF THE COMPANY
Upon completion of the Offering, Mr. Williams and certain individuals
related to, and entities associated with him (collectively, the "Affiliated
Holders") will own directly and indirectly, in the aggregate, 48.7% of the
outstanding Common Stock (or 47.7% if the Underwriters' over-allotment option is
exercised in full). Accordingly, the Affiliated Holders will be able to exercise
significant influence over the election of the directors of the Company and the
control of the Company's management, operations and affairs. The voting power
held by Affiliated Holders and their ability to exercise significant influence
over the election of directors may have the effect of delaying, deterring or
preventing certain types of transactions involving an actual or potential change
of control of the Company, including transactions in which the holders of Common
Stock might otherwise receive a premium for their shares over then current
market prices. See "Principal Stockholders" and "Description of Capital Stock."
OPERATING HAZARDS; UNINSURED RISKS
The oil and gas business involves a variety of operating risks, including
the risk of fire, explosions, blow-outs, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures and discharges of toxic gases, the occurrence of any of
which could result in substantial losses to the Company due to injury and loss
of life, damage to and destruction of property and equipment, pollution and
other environmental damage and related suspension of operations. Gathering
systems and processing plants are subject to many of the same hazards and any
significant problems related to those facilities could adversely affect the
Company's ability to market its production. Drilling activities are subject to
numerous risks, including the risk that no commercially productive oil or gas
reservoirs will be encountered or that particular wells will not produce at
economic levels. The cost of drilling, completing and operating wells may vary
from initial estimates. Drilling activities may be curtailed, delayed or
canceled as a result of numerous factors outside the Company's control,
including but not limited to title problems, weather conditions, compliance with
governmental requirements, mechanical difficulties and shortages or delays in
the delivery of drilling rigs or other equipment. The Company maintains
insurance against some, but not all potential risks; however, there can be no
assurance that such insurance will be adequate to cover any losses or exposure
to liability. Furthermore, the Company cannot predict whether insurance will
continue to be available at premium levels that justify its purchase or whether
insurance will be available at all.
REGULATION
Virtually all of the Company's oil and gas activities are subject to a wide
variety of federal, state and local governmental regulations, which are changed
from time to time in response to economic or political conditions. Matters
subject to regulation include, but are not limited to, environmental matters,
discharge permits for drilling operations, drilling and operating bonds, reports
concerning operations, the spacing of wells, unitization and pooling of
properties, allowable rates of production, restoration of surface areas,
plugging and abandonment of wells, requirements for the operation of wells and
taxation. From time to time, regulatory agencies have imposed price controls and
limitations on production by restricting the rate
11
<PAGE>
of flow of oil and gas wells below actual production capacity in order to
conserve supplies of oil and gas. Many states have raised state taxes on energy
sources and additional increases may occur, although there can be no certainty
of the effect that such increases would have on the Company. Legislation and new
regulations concerning oil and gas exploration and production operations are
constantly being reviewed and proposed. All of the jurisdictions in which the
Company owns and operates properties have statutes and regulations governing a
number of the matters enumerated above. Compliance with such laws and
regulations generally increases the Company's cost of doing business and
consequently affects its profitability. Due to the frequently changing
requirements of laws and regulations, there can no assurance that costs of
future compliance will not impose new or substantial burdens on the Company. See
"Business and Properties--Regulation."
ENVIRONMENTAL MATTERS
The discharge of oil, gas or other pollutants into the air, soil or water
may give rise to liabilities to governmental agencies and third parties, and may
require the Company to incur costs to remedy such discharges. Oil, natural gas
and other pollutants (including salt water brine) may be discharged in many
ways, including from a well or drilling equipment at a drill site, leakage from
pipelines or other gathering and transportation facilities, leakage from storage
tanks and tailings ponds, and sudden discharges from damage or explosion at
natural gas facilities, oil and gas wells or other facilities. Discharged
hydrocarbons and other pollutants may migrate through soil to water supplies or
adjoining property, giving rise to additional liabilities. A variety of federal,
state and local laws and regulations govern the environmental aspects of oil and
natural gas exploration, production, transportation and processing and may, in
addition to other laws and regulations, impose liability in the event of
discharges (whether or not accidental), failure to notify the proper authorities
of a discharge, and other failures to comply with those laws and regulations.
Compliance with environmental quality requirements and reclamation laws imposed
by governmental authorities may necessitate significant capital outlays, may
materially affect the acquisition or operating costs of a given property, or may
cause material changes or delays in the Company's intended activities.
Management of the Company does not believe that its environmental, health, and
safety risks are materially different from those of comparable companies engaged
in similar businesses. Nevertheless, new or different environmental standards
imposed in the future may adversely affect the Company's activities and there
can be no assurance that significant costs for compliance will not be incurred
in the future. Moreover, no assurance can be given that environmental laws will
not, in the future, result in curtailment of production or material increases in
the cost of exploration, development or production or otherwise adversely affect
the Company's operations and financial condition. See "Business and Properties--
Environmental Matters."
COMPETITION
The Company operates in a highly competitive environment. The Company
competes with major and independent oil and gas companies for the acquisition of
desirable oil and gas properties, as well as for the equipment and labor
required to develop and operate such properties. Many competitors have
substantially larger financial resources, staffs and facilities. See "Business
and Properties--Competition and Markets."
CERTAIN ANTI-TAKEOVER PROVISIONS
The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain certain provisions that may have the effect of
discouraging unsolicited takeover proposals for the Company. The Certificate of
Incorporation and Bylaws provide that the Company's Directors will be divided
into three classes, with the directors of each class serving staggered terms of
three years each or until their respective successors are elected and qualified
and that the Directors may issue serial preferred stock with such rights and
preferences as the Board may determine, without stockholder approval. The
Delaware General Corporation Law imposes additional restrictions on business
combinations with certain interested parties. See "Description of Capital
Stock--Delaware Takeover Statute."
12
<PAGE>
USE OF PROCEEDS
The net proceeds to the Company from the sale of the 1,250,000 shares of
Common Stock offered hereby, after deducting underwriting discounts and
commissions and estimated expenses of the Offering are estimated to be
approximately $14.9 million ($17.2 million if the Underwriters' over-allotment
option is exercised in full). The net proceeds will be used initially to reduce
indebtedness under the Credit Facility. The Company intends to use such
increased borrowing capacity, together with internally generated funds, to (i)
finance its 1997 planned capital expenditure program and (ii) conduct and
evaluate one or more 3-D seismic surveys in connection with the Cotton Valley
Exploratory Project. To date, the Company has committed to conduct a seismic
survey covering approximately 20,000 acres in Robertson County at a cost of
approximately $3.1 million, including interpretation. The Company anticipates
that the survey will be completed during the first quarter of 1997 and that the
resulting data will be interpreted during the second quarter of 1997. The
Company may conduct additional surveys covering other portions of the North
Giddings Block.
The Credit Facility, which was renewed in July 1996, established a revolving
loan facility with an initial borrowing base of $52 million, subject to a
monthly commitment reduction of $1 million. As of September 30, 1996, the
adjusted borrowing base was $49.0 million and the outstanding indebtedness under
the Credit Facility was $36.5 million, resulting in an availability at that date
of $12.5 million. The borrowing base and the monthly commitment reduction are
scheduled to be redetermined in November 1996 and at least semi-annually
thereafter; however, the Company or the banks may request such redeterminations
at any other time during the year. Any redetermination will be made at the
discretion of the banks. If, at any time, outstanding advances plus letters of
credit exceed the borrowing base, 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 outstanding
under the Credit Facility to a term obligation based on amortization formulas
set forth in the loan agreement. The Company has pledged its oil and gas
properties to secure advances under the Credit Facility and contains standard
restrictive covenants dealing with the Company's ability to incur additional
indebtedness, grant liens on its properties and other matters. 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 a fluctuating base
rate plus a base rate margin ranging from 0% to 0.5% per annum, depending on
levels of outstanding advances and letters of credit. Eurodollar Loans bear
interest at the LIBOR rate for a fixed period of time elected by the Company
plus a Eurodollar margin ranging from 1.25% to 2% per annum. In addition, the
Company pays the banks a commitment fee equal to 0.5% per annum on the unused
portion of the revolving loan commitment. Interest and fees are payable
quarterly, and all outstanding principal and interest will be due July 31, 1999.
13
<PAGE>
PRICE RANGE OF COMMON STOCK
The Common Stock is quoted on the Nasdaq National Market under the symbol
"CWEI." The following table sets forth, for the periods indicated, the high and
low sale prices of the Common Stock as reported on the Nasdaq National Market.
<TABLE>
<CAPTION>
HIGH LOW
------- -------
<S> <C> <C>
YEAR ENDING DECEMBER 31, 1996:
Fourth Quarter (through November 13, 1996)........................................... $14 1/4 $ 9 5/8
Third Quarter........................................................................ 12 7 3/8
Second Quarter....................................................................... 10 7/8 3 3/4
First Quarter........................................................................ 4 3/8 2 5/8
YEAR ENDED DECEMBER 31, 1995:
Fourth Quarter....................................................................... $ 3 3/8 $ 2
Third Quarter........................................................................ 3 5/8 2 3/8
Second Quarter....................................................................... 4 3/4 2 3/4
First Quarter........................................................................ 6 1/2 3 3/4
YEAR ENDED DECEMBER 31, 1994:
Fourth Quarter....................................................................... $ 9 1/4 $ 5
Third Quarter........................................................................ 9 1/2 6 1/2
Second Quarter....................................................................... 10 3/4 6 1/2
First Quarter........................................................................ 15 10
</TABLE>
The quotations in the table above reflect inter-dealer prices without retail
markups, markdowns or commissions. On November 13, 1996, the last reported sale
price for the Common Stock on the Nasdaq National Market was $13 1/4. As of
November 13, 1996, the Company had approximately 1,100 beneficial and record
stockholders.
DIVIDEND POLICY
The Company has not paid any dividends since its inception and for the
foreseeable future intends to follow a policy of retaining all of its earnings,
if any, to finance the development and continued expansion of its business.
There can be no assurance that dividends will ever be paid by the Company.
Pursuant to the terms of the Credit Facility, the Company is currently limited
in its ability to pay dividends on its Common Stock (except dividends paid in
shares of Common Stock) to an amount which does not exceed 50% of the Company's
net income for the fiscal year in which the dividends are declared. Any future
determination as to payment of dividends will depend upon the Company's
financial condition, results of operations and other such factors as the Board
of Directors deems relevant.
14
<PAGE>
CAPITALIZATION
The following table sets forth the total consolidated capitalization of the
Company at September 30, 1996, and as adjusted to reflect the issuance of
1,250,000 shares of Common Stock offered by the Company, and the application of
the estimated net proceeds therefrom, as described under "Use of Proceeds." The
following table should be read in conjunction with the Consolidated Financial
Statements of the Company and the related notes thereto and other financial
information included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
AT SEPTEMBER 30, 1996
-----------------------
ACTUAL AS ADJUSTED
---------- -----------
<S> <C> <C>
(IN THOUSANDS)
Long-term debt................................................................. $ 36,522 $ 21,604
---------- -----------
Stockholders' equity:
Preferred Stock, par value $.10 per share; 3,000,000 shares authorized; no
shares issued and outstanding.............................................. -- --
Common Stock, par value $.10 per share; 15,000,000 shares authorized;
7,490,321 shares issued and outstanding (8,740,321 shares as adjusted)
(1)........................................................................ 749 874
Additional paid-in capital................................................... 53,264 68,057
Retained deficit............................................................. (11,344) (11,344)
---------- -----------
Total stockholders' equity................................................. 42,669 57,587
---------- -----------
Total capitalization....................................................... $ 79,191 $ 79,191
---------- -----------
---------- -----------
</TABLE>
- ------------------------
(1) Does not include 7,895 shares of Common Stock issued pursuant to stock
compensation plans subsequent to September 30, 1996 and 270,048 shares of
Common Stock issuable upon exercise of currently outstanding options.
15
<PAGE>
SELECTED FINANCIAL INFORMATION
(IN THOUSANDS, EXCEPT PER SHARE DATA)
The following table sets forth summary consolidated financial data of the
Company for each of the five years ended December 31, 1995, which have been
derived from the Company's audited Consolidated Financial Statements. The
financial data for each of the three years ended December 31, 1993 include the
historical results of the Company and its Predecessors prior to the
Consolidation. The financial data of the Company for the nine months ended
September 30, 1995 and 1996 have been derived from the Company's unaudited
interim Consolidated Financial Statements, which in the opinion of management of
the Company, have been prepared on the same basis as the annual Consolidated
Financial Statements and include all adjustments (consisting of only normal
recurring adjustments) necessary for a fair presentation of the financial data
for such periods. The information in this table should be read in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements and the notes thereto
included elsewhere herein. The results for the nine month period ended September
30, 1996 are not necessarily indicative of results for the full year.
<TABLE>
<CAPTION>
NINE
MONTHS
ENDED
SEPTEMBER
YEAR ENDED DECEMBER 31, 30,
----------------------------------------------------- ---------
1991 1992 1993 1994 1995 1995
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
(UNAUDITED)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales..................................... $ 80,042 $ 60,134 $ 55,041 $ 43,617 $ 43,883 $ 33,133
Natural gas services.................................. 5,859 5,159 4,554 5,868 5,388 4,494
--------- --------- --------- --------- --------- ---------
Total revenues...................................... 85,901 65,293 59,595 49,485 49,271 37,627
--------- --------- --------- --------- --------- ---------
Costs and expenses:
Lease operations...................................... 15,873 13,459 12,788 12,775 13,533 10,231
Exploration........................................... 8,432 4,365 6,198 7,139 1,555 863
Natural gas services.................................. 3,677 2,746 2,518 3,510 3,714 3,038
Depreciation, depletion and amortization.............. 39,348 28,769 26,751 25,248 25,110 20,011
Impairment of property and equipment.................. -- -- -- -- 10,259 --
General and administrative............................ 6,068 5,416 6,876 5,659 3,708 2,739
--------- --------- --------- --------- --------- ---------
Total costs and expenses............................ 73,398 54,755 55,131 54,331 57,879 36,882
--------- --------- --------- --------- --------- ---------
Operating income (loss)............................. 12,503 10,538 4,464 (4,846) (8,608) 745
Interest expense...................................... 6,339 6,807 4,003 4,461 5,493 4,224
Other income (expense) (1)............................ 416 (740) 149 759 6,022 6,198
--------- --------- --------- --------- --------- ---------
Income (loss) before income taxes..................... 6,580 2,991 610 (8,548) (8,079) 2,719
Income taxes (2)...................................... 2,237 1,017 207 -- -- --
--------- --------- --------- --------- --------- ---------
Net income (loss)..................................... $ 4,343 $ 1,974 $ 403 $ (8,548) $ (8,079) $ 2,719
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Net income (loss) per common share.................... $ 1.36 $ 0.62 $ 0.09 $ (1.50) $ (1.31) $ 0.47
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
Weighted average common shares outstanding............ 3,200 3,200 4,700 5,700 6,165 5,750
OTHER DATA:
Net cash provided by operating activities............... $ 54,134 $ 27,795 $ 29,716 $ 23,672 $ 24,201 $ 19,688
EBITDAX (3)............................................. 60,283 43,672 37,413 27,541 28,316 21,619
EBITDAX per share....................................... 18.84 13.65 7.96 4.83 4.59 3.76
<CAPTION>
1996
---------
<S> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales..................................... $ 42,136
Natural gas services.................................. 2,914
---------
Total revenues...................................... 45,050
---------
Costs and expenses:
Lease operations...................................... 10,808
Exploration........................................... 515
Natural gas services.................................. 2,363
Depreciation, depletion and amortization.............. 17,743
Impairment of property and equipment.................. 1,186
General and administrative............................ 2,399
---------
Total costs and expenses............................ 35,014
---------
Operating income (loss)............................. 10,036
Interest expense...................................... 2,783
Other income (expense) (1)............................ 60
---------
Income (loss) before income taxes..................... 7,313
Income taxes (2)...................................... --
---------
Net income (loss)..................................... $ 7,313
---------
---------
Net income (loss) per common share.................... $ 0.96
---------
---------
Weighted average common shares outstanding............ 7,588
OTHER DATA:
Net cash provided by operating activities............... $ 30,047
EBITDAX (3)............................................. 29,480
EBITDAX per share....................................... 3.89
</TABLE>
<TABLE>
<CAPTION>
AT DECEMBER 31, AT SEPTEMBER 30, 1996
------------------------------- ----------------------------
1993 1994 1995 ACTUAL AS ADJUSTED (4)
--------- --------- --------- ----------- ---------------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)............................ $ (3,891) $ (12,269) $ (13,717) $ (5,559) $ (5,559)
Total assets......................................... 116,116 111,746 93,161 95,647 95,647
Long-term debt....................................... 49,283 49,147 33,538 36,522 21,604
Stockholders' equity................................. 47,474 38,926 34,996 42,669 57,587
</TABLE>
- ------------------------------
(1) The 1995 periods include a $6.0 million non-recurring gain on sale of the
Company's two principal gas gathering and processing systems.
(2) Prior to the Consolidation, income taxes were computed at the applicable
federal statutory rate.
(3) EBITDAX refers to earnings before income taxes, interest expense,
depreciation, depletion and amortization, impairment of property and
equipment, exploration costs, and other income (expense). EBITDAX is a
financial measure commonly used in the Company's industry and should not be
considered in isolation or as a substitute for net income, cash flow
provided by operating activities or other income or cash flow data prepared
in accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity.
(4) As adjusted to reflect receipt by the Company of estimated net proceeds from
the issuance of 1,250,000 shares of Common Stock and the application of such
proceeds. See "Use of Proceeds" and "Capitalization."
16
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding the
Company's historical consolidated financial position at December 31, 1993, 1994
and 1995, and September 30, 1996, and results of operations and cash flows for
each of the three years in the period ended December 31, 1995 and the unaudited
nine month periods ended September 30, 1995 and 1996. The Company's historical
Consolidated Financial Statements and notes thereto included elsewhere in this
Prospectus contain detailed information that should be referred to in
conjunction with the following discussion.
OVERVIEW
The Company commenced operations in May 1993, following the Consolidation
and completion of the Company's initial public offering. The Company and its
predecessors have been engaged in the exploration for and development and
production of oil and gas in the Trend since 1976. During the 20-year period,
the Company has continually adapted its Trend drilling techniques to take
advantage of technological advancements available to the industry, particularly
in the area of horizontal drilling tools.
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, the Company must find and develop or
acquire proven reserves sufficient to replace those being depleted through
current production. The Company has attempted to supplement its Trend reserves
with longer-life reserves by diversifying its activities into (i) foreign
exploration and development ventures, (ii) 3-D exploration projects in areas of
Texas other than the Trend, and (iii) acquisitions of producing properties.
Although the Company has enjoyed some success through the acquisition of
properties in the Jalmat Field of New Mexico and the Texas Gulf Coast area, none
of the Company's exploration activities conducted outside the Trend during 1993
and 1994 were commercially productive. As a result, the Company determined in
1995 to direct its efforts in the North Giddings Block, where it has developed
substantial experience, and presently plans to continue to explore for and
develop oil and gas reserves from the North Giddings Block during the remainder
of 1996 and in 1997.
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.
17
<PAGE>
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the Company
for the periods presented:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (Mbbls)................................................... 1,881 1,709 1,831 1,376 1,601
Gas (Mmcf).................................................... 10,364 8,369 6,845 5,377 4,183
Total (MBOE).................................................. 3,608 3,104 2,972 2,272 2,298
AVERAGE OIL AND GAS SALES PRICES (1):
Oil ($/Bbl)................................................... $ 17.41 $ 15.72 $ 17.35 $ 17.40 $ 19.76
Gas ($/Mcf)................................................... $ 2.15 $ 1.98 $ 1.77 $ 1.70 $ 2.48
OPERATING COSTS AND EXPENSES ($/BOE PRODUCED):
Lease operations.............................................. $ 3.54 $ 4.12 $ 4.55 $ 4.50 $ 4.70
Oil and gas depletion......................................... $ 7.03 $ 7.81 $ 8.16 $ 8.51 $ 7.46
General and administrative.................................... $ 1.90 $ 1.82 $ 1.24 $ 1.21 $ 1.04
NET WELLS DRILLED:
Horizontal wells.............................................. 27.6 16.2 23.5 18.5 17.2
Vertical wells................................................ 0.1 3.6 -- -- 1.1
</TABLE>
- ------------------------
(1) Includes effects of hedging transactions.
NINE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1995
REVENUES
Oil and gas sales increased 27% from $33.1 million during the nine months
ended September 30, 1995 to $42.1 million during the nine months ended September
30, 1996 due primarily to a 16% increase in oil production, a 14% increase in
oil prices (net of hedging losses), and a 46% increase in gas prices. These
benefits were offset in part by a 22% decline in gas production. Production from
wells completed subsequent to September 30, 1995 accounted for approximately 37%
of total oil production for the 1996 period, which more than offset the effects
of steep production declines from previously existing Trend wells.
Revenues from natural gas services decreased 36% from $4.5 million during
the nine months ended September 30, 1995 to $2.9 million during the nine months
ended September 30, 1996 due primarily to the sale of the Company's two
principal gas gathering and processing systems in August 1995, and offset in
part by additional revenues generated in 1996 related to a gas plant and three
gathering systems acquired in 1996.
COSTS AND EXPENSES
Lease operations expenses increased 6% from $10.2 million during the nine
months ended September 30, 1995 to $10.8 million during the nine months ended
September 30, 1996 while production on a BOE basis increased 1%, resulting in an
increase in lease operations expenses on a BOE basis from $4.50 per BOE during
the 1995 period to $4.70 per BOE during the 1996 period. Such increase was due
primarily to higher production taxes resulting from a 27% increase in oil and
gas sales.
Although exploration costs were relatively insignificant during each of the
nine month periods ended September 30, 1995 and 1996, the Company expects
exploration costs to increase significantly during 1997 due to the initiation of
the Cotton Valley Exploratory Project. To date, the Company has committed to
18
<PAGE>
spend approximately $3.1 million to conduct and evaluate a 3-D seismic survey
covering approximately 20,000 acres in the North Giddings Block. In addition,
the Company may conduct additional surveys covering other portions of the North
Giddings Block and may drill one or more exploratory wells on any prospects
which result from such surveys. 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 such costs are incurred
and expensed.
Depreciation, depletion and amortization ("DD&A") expense decreased 12% from
$20.0 million during the 1995 period to $17.7 million during the 1996 period due
primarily to a 12% decline in the Company's average depletion rate per BOE.
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 lower depletion rate is attributable to a combination of
higher proved reserves from newly completed wells and lower depletable costs
resulting from the impairment of certain producing properties in October 1995
and June 1996 pursuant to Statement of Financial Accounting Standards No. 121,
"Accounting for Impairment of Long-Lived Assets" ("SFAS 121"). As a result, the
average depletion rate declined from $8.51 per BOE during the 1995 period to
$7.46 per BOE during the 1996 period.
The Company recorded a provision for impairment of property and equipment of
$1.2 million during the second quarter of 1996 in accordance with SFAS 121.
General and administrative ("G&A") expenses decreased 11% from $2.7 million
during the 1995 period to $2.4 million during the 1996 period. Beginning in
March 1994, the Company reduced its overhead by implementing certain cost
reduction measures, including the closing of its San Antonio office, the
elimination or reduction of certain professional services, and the control of
personnel costs through staff and wage reductions and employee benefit cost
controls. The full impact of these measures was realized during the third
quarter of 1995.
Costs of natural gas services decreased 20% from $3.0 million during the
1995 period to $2.4 million during the 1996 period due primarily to the sale of
the Company's two principal gas gathering and processing systems in August 1995,
and offset in part by additional costs incurred in 1996 related to a gas plant
and three gathering systems acquired in 1996.
INTEREST EXPENSE AND OTHER
Interest expense decreased 33% from $4.2 million during the 1995 period to
$2.8 million during the 1996 period due primarily to lower average levels of
indebtedness on the Company's secured bank credit facility and, to a lesser
extent, lower average interest rates. The average daily principal balance
outstanding on such facility during the 1996 period was $39.7 million compared
to $55.3 million in 1995. The effective annual interest rate on bank debt during
the 1996 period was 9.5% compared to 10.3% in 1995. Proceeds from the sales of
assets in August 1995 and January 1996 and the sale of Common Stock through a
shareholder rights offering in September 1995, which aggregated approximately
$15 million, were used to reduce bank indebtedness.
Other income decreased from $6.2 million during the 1995 period to $60,000
during the 1996 period. In August 1995, XCEL Gas Company, a general partnership
in which the Company owned a 77% interest, sold its interest in a gas gathering
system, and the Company sold its 43% interest in the El Campo gas processing
system, for aggregate net proceeds of $7.7 million, resulting in a combined gain
on sale of property and equipment of $6.0 million, net to the Company.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
REVENUES
Oil and gas sales increased 1% from $43.6 million in 1994 to $43.9 million
in 1995 due primarily to higher oil prices, the benefit of which was largely
eliminated by the effects of lower gas prices and a 4%
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<PAGE>
decline in oil and gas production. Although production from wells completed
after December 31, 1994 accounted for 33% of the Company's 1995 production,
these additions were more than offset by characteristically steep production
declines from previously existing Trend wells. Average prices received for oil
production increased 10% while average gas prices declined 11%.
Revenues from natural gas services decreased 8% from $5.9 million in 1994 to
$5.4 million in 1995, despite the sale in August 1995 of the Company's two
principal gas gathering and processing systems, since one of the systems sold
was acquired effective January 1995 and did not contribute to revenues in 1994.
COSTS AND EXPENSES
Lease operations expenses increased 5% from $12.8 million in 1994 to $13.5
million in 1995 despite a 4% decline in BOE production. On a BOE basis, lease
operations expenses increased from $4.12 per BOE to $4.55 per BOE. Operating
expenses of Trend wells are generally lower on a BOE basis in the early stages
of production since a large portion of the operating expenses are fixed in
nature and do not vary with production volume. As production volumes decline,
operating expenses per BOE typically increase. In addition, during 1995, the
Company conducted most of its drilling activity in the updip area of the Trend
where the reservoir pressures are lower. Generally, this requires wells to be
converted from flowing wells to electric-powered pumping units at an earlier
stage of production, which increases the lifting costs associated with the updip
wells.
Effective October 1, 1995, the Company adopted SFAS 121, and recorded a
$10.3 million non-cash provision for impairment of certain producing assets.
Substantially all of the impaired assets are located in the Pearsall Field in
the Trend.
DD&A expense remained constant from 1994 to 1995, despite a 4% decline in
production, due to slightly higher amortization rates per BOE. 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
effects on amortization rates of a 15% downward revision of estimated proved
reserves at December 31, 1994 were substantially offset by the adoption of SFAS
121, which reduced DD&A rates on the impaired properties.
G&A expenses decreased 35% from $5.7 million in 1994 to $3.7 million in
1995. Since March 1994, the Company has reduced its overhead by implementing
certain cost reduction measures, including the closing of its San Antonio
office, the elimination or reduction of certain professional services, and the
control of personnel costs through staff and wage reductions and employee
benefit cost controls. The benefit of these measures was fully realized in 1995.
Exploration costs decreased 77% from $7.1 million in 1994 to $1.6 million in
1995 due primarily to provisions for dry hole costs, impairments of unproved
properties and seismic expenses in 1994 related to the Company's acreage in the
Sabine Area of the Trend, its Argentina venture and its West and North Central
Texas 3-D seismic program which did not recur in 1995.
Costs of natural gas services increased 6% from $3.5 million in 1994 to $3.7
million in 1995 despite the sale in August 1995 of the Company's two principal
gas gathering and processing systems. The reduction in costs related to the
assets sold was more than offset by the fact that one of the systems sold was
acquired effective January 1995 and did not contribute to costs in 1994.
INTEREST EXPENSE AND OTHER
Interest expense increased 22% from $4.5 million in 1994 to $5.5 million in
1995 due primarily to higher average interest rates on the Credit Facility. The
effective annual interest rate on bank debt during 1995 was 10.6% compared to
8.7% in 1994. Proceeds from the sale of certain natural gas gathering and
processing systems in August 1995 and the sale of Common Stock pursuant to a
rights offering in September 1995 resulted in a slight reduction in average
levels of bank debt in 1995. The average daily
20
<PAGE>
principal balance outstanding on bank debt during 1995 was $52.3 million
compared to $52.6 million in 1994.
Other income increased from $800,000 in 1994 to $6.0 million in 1995. In
August 1995, the Company sold certain gas gathering assets for aggregate net
proceeds of $7.7 million, resulting in a combined gain on sale of property and
equipment of $6.0 million, net to the Company.
YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993
REVENUES
Oil and gas sales decreased 21% from $55.0 million in 1993 to $43.6 million
in 1994 due to a combination of lower oil and gas production and lower product
prices. Oil and gas production on a BOE basis decreased 14% from 1993. Trend
wells drilled in 1994 accounted for 12% of 1994 oil and gas production, while
1994 acquisitions contributed 2%, both of which were more than offset by the
steep production declines which are characteristic of Trend wells. In addition,
prices received for oil and gas production also declined during 1994 by 10% and
8%, respectively, accounting for approximately one-third of the 21% decrease in
oil and gas sales.
Revenues from natural gas services increased 28% from $4.6 million in 1993
to $5.9 million in 1994 due primarily to additional revenues generated in 1994
from the Company's Mentone gas treatment facility which was completed in August
1993 and additional revenues generated through third party gas marketing
arrangements originating in December 1993.
COSTS AND EXPENSES
Lease operations expenses remained relatively constant in 1994 as compared
to 1993 despite a 14% decline in BOE production. On a BOE basis, lease
operations expenses increased from $3.54 per BOE to $4.12 per BOE. Operating
expenses of Trend wells are generally lower on a BOE basis in the early stages
of production since a large portion of the operating expenses are fixed in
nature and do not vary with production volume. As production volumes decline,
operating expenses per BOE generally increase. In addition, during 1994, the
Company conducted most of its drilling activity in the updip area of the Trend
where the reservoir pressures are lower. Generally, this requires wells to be
converted from flowing wells to electric-powered pumping units at an earlier
stage of production, which increases the lifting costs associated with the updip
wells.
DD&A expense decreased 6% from $26.8 million in 1993 to $25.2 million in
1994 due to a 14% decline in BOE production which was offset in part by higher
amortization rates per BOE. 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. Quantities of estimated proved reserves were
revised downward by 15% on a BOE basis during 1994, contributing to an increase
in the depletion rate for the fourth quarter of 1994 to $9.11 per BOE compared
to $7.81 per BOE for the entire 1994 year.
G&A expenses decreased 17% from $6.9 million in 1993 to $5.7 million in 1994
despite the incurrence of $601,000 of G&A expenses attributable to the Company's
Argentina venture in 1994. In March 1994, and again in January 1995, the Company
implemented certain cost reduction measures, including the elimination of three
senior level positions, in order to reduce overhead and conserve financial
resources. The Company reduced professional fees significantly during 1994. In
addition, the Company closed its San Antonio office and consolidated all
exploration and production functions, other than field operations, into its
corporate headquarters in Midland.
Exploration costs increased 15% from $6.2 million in 1993 to $7.1 million in
1994 due primarily to increases in provisions for dry holes and impairments of
unproved properties, offset in part by reductions in seismic expenses. During
1994, the Company recorded provisions for impairments of other unproved acreage
totaling $2.6 million, the most significant of which was attributable to the
Sabine area of the Trend.
21
<PAGE>
In addition, the Company recorded a provision for dry holes and abandonments of
$2.5 million related to an unsuccessful exploration venture in the Colhue Huapi
area of Argentina and expensed $1.4 million of seismic costs, dry hole costs and
leasehold impairments related to a 3-D seismic program in West and North Central
Texas initiated in 1993. By comparison, the 1993 exploration costs included $2.4
million of dry hole costs related to the unsuccessful results of two exploratory
wells, $1.9 million of leasehold impairments (primarily related to the Sabine
area of the Trend) and $1.5 million of seismic costs related to the West and
North Central Texas 3-D program.
Costs of natural gas services increased 40% from $2.5 million in 1993 to
$3.5 million in 1994 due primarily to the third party gas marketing arrangements
discussed under "Revenues" above. Since these arrangements are typically
characterized by low gross profit margins, the percentage increase in costs was
disproportionately higher than the associated percentage increase in revenues.
INTEREST EXPENSE AND OTHER
Interest expense increased 13% from $4.0 million in 1993 to $4.5 million in
1994 due to higher average interest rates during 1994, offset in part by lower
average levels of bank indebtedness. The effective annual interest rate on bank
debt during 1994 was 8.7% compared to 7.6% in 1993. The average daily principal
balance outstanding on bank debt during 1994 was $52.6 million compared to $54.1
million in 1993.
Included in other income during 1994 was a $600,000 gain related to a
favorable ruling in a legal proceeding for which a loss provision had been
recorded in 1992.
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.
The following discussion sets forth the Company's current plans for capital
expenditures in 1996 and 1997, and the expected capital resources needed to
finance such plans.
CAPITAL EXPENDITURES
During the remainder of 1996 and in 1997, the Company plans to focus its
efforts in the North Giddings Block. During the nine months ended September 30,
1996, the Company completed 17 net wells in the North Giddings Block and plans
to drill an additional 7 net wells in this area during the remainder of 1996. In
addition, the Company is also actively acquiring additional acreage and
extending the terms of existing leases in the North Giddings Block.
The Company's capital expenditures are expected to be approximately $33
million in 1996, of which $25 million was incurred in the first nine months of
1996. In response to favorable oil prices and drilling results, the Company
intends to accelerate its drilling program by contracting for a third drilling
rig beginning in December 1996. At this increased level of drilling activity,
the Company plans to incur capital expenditures of approximately $42 million
during 1997. In addition, the Company has committed to spend approximately $3.1
million in 1997 to conduct and evaluate a proprietary 3-D seismic survey
covering a portion of its acreage in connection with the Cotton Valley
Exploratory Project and may conduct additional surveys covering other portions
of the North Giddings Block. Substantially all of the planned future activity is
discretionary. This allows the Company to make adjustments to its level of
capital and exploratory
22
<PAGE>
expenditures based upon such factors as the availability of capital resources,
product prices and drilling results. Thus, if the Company's ability or desire to
conduct the planned activities is diminished or enhanced by any of these
factors, the Company can modify its capital expenditures accordingly. The
Company's current policy is to limit its annual Cotton Valley Exploratory
Project expenditures to not more than 25% of its planned annual capital
expenditures. However, the Company may modify this policy depending upon certain
factors, including the Company's financial position, exploratory drilling
success, technological advances, drilling activities conducted by third parties
and current and anticipated product prices. See "-- Capital Resources" and
"Business and Properties--Cotton Valley Exploratory Project."
The Company does not have any specified amounts of capital expenditures
designated for acquisitions of proven properties in 1996 and 1997. However, the
Company plans to actively seek and evaluate acquisition opportunities and will
commit only to those acquisitions which the Company can adequately finance
through internal and external sources.
CAPITAL RESOURCES
CREDIT FACILITY. The Company had $12.5 million of funds available to it
under the Credit Facility at September 30, 1996. The banks' loan commitment
currently reduces by $1 million each month. Net proceeds from the Offering will
initially be utilized to reduce indebtedness under the Credit Facility. The
Company intends to use such increased borrowing capacity, together with
internally generated funds, to (i) finance its 1997 planned capital expenditure
program and (ii) conduct and evaluate one or more proprietary 3-D seismic
surveys as a part of the Cotton Valley Exploratory Project. See "Use of
Proceeds."
WORKING CAPITAL AND CASH FLOW. During the nine months ended September 30,
1996, the Company generated cash flow from operating activities of $30.0 million
and received proceeds from the sale of assets of $3.5 million. During the same
period, the Company spent $25.3 million on capital expenditures and repaid $5.7
million on the term loan facility. The residual cash flow of $2.5 million was
primarily used to reduce the amount of indebtedness outstanding on the revolving
loan facility.
The Company's working capital deficit decreased from $13.7 million at
December 31, 1995 to $5.6 million at September 30, 1996 due primarily to a
reduction in current portion of long-term debt. Based upon the initial borrowing
base and scheduled commitment reductions set forth in the Credit Facility, no
portion of the outstanding balance on the Company's secured bank credit facility
is deemed to be a current liability at September 30, 1996.
The Company believes that the funds to be available under the Credit
Facility following the Offering and cash provided by operations will be adequate
to fund the Company's operations and projected capital and exploratory
expenditures during the remainder of 1996 and 1997. However, because future cash
flows and the availability of borrowings are subject to a number of variables,
such as the level of production from existing wells, the Company's success in
locating and producing new reserves, prevailing prices of oil and gas, and the
uncertainty with respect to the amount of funds which may ultimately be required
to finance the Cotton Valley Exploratory Project, there can be no assurance that
the Company's capital resources will be sufficient to sustain the Company's
exploratory and development activities, even with the proceeds of this Offering.
If such capital resources are insufficient, the Company may be required to cease
or delay such activities.
INFLATION AND CHANGES IN PRICES
The Company's revenues and the value of its oil and gas properties have been
and will continue to be affected by changes in oil and gas prices. The Company's
ability to maintain adequate borrowing capacity and to obtain additional capital
on attractive terms is also substantially dependent on oil and gas prices. Oil
and gas prices are subject to significant seasonal and other fluctuations that
are beyond the Company's ability to control or predict. In an attempt to manage
this price risk, the Company from time to time engages in hedging transactions.
Although certain of the Company's costs and expenses are affected by the
level of inflation, inflation did not have a significant effect on the Company's
results of operations during 1996.
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<PAGE>
HEDGING TRANSACTIONS
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to achieve a more predictable
cash flow, as well as to reduce its exposure to price fluctuations. While the
use of these hedging arrangements limits the downside risk of price declines,
such use may also limit any benefits which may be derived from price increases.
The Company uses various financial instruments, such as swaps and collars,
whereby monthly settlements are based on differences between the prices
specified in the instruments and the settlement prices of certain futures
contracts quoted on the New York Mercantile Exchange ("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 allows for the future delivery of the hedged products.
As of the date of this Prospectus, the Company has no open positions in
swap, collar or other financial hedging arrangements. However, the Company may
in the future enter into various hedging arrangements in order to realize
commodity prices which it considers favorable under the circumstances.
24
<PAGE>
BUSINESS AND PROPERTIES
GENERAL
Clayton Williams Energy, Inc. is primarily engaged in the exploration,
development and production of oil and natural gas, and to a lesser extent, in
the gathering and marketing of natural gas. Since 1988, the Company and its
predecessors have concentrated their drilling activities primarily in the Trend,
which extends from South Texas through East Texas, Louisiana and other southern
states and includes the Austin Chalk formation. The Company also has operations
in the Jalmat Field located in southeastern New Mexico and in the Texas Gulf
Coast. As of June 30, 1996, the Company had estimated proved reserves totaling
6,844 Mbbls of oil and 37.7 Bcf of gas with a PV-10 Value of approximately
$100.3 million as estimated by the Independent Engineers. At June 30, 1996, the
Company held interests in 455 gross (337.1 net) oil and gas wells and owned
leasehold interests in approximately 191,289 gross (129,632 net) undeveloped
acres.
BUSINESS STRATEGY
The Company's business strategy is to increase reserves and production
through exploration and development of its oil and gas properties, concentrating
its efforts in the Trend. The Company has operated in the Trend for 20 years and
drilled or participated in the drilling of 634 gross vertical and horizontal
wells through June 30, 1996. Development of the Austin Chalk formation, which is
characterized by fractured carbonate reservoirs, has been enhanced by advances
in horizontal drilling and completion technologies since the early 1990's. These
advances have provided the Company with the opportunity to develop new reserves
and to generate more attractive economic returns in the Austin Chalk formation.
The Company believes that it is one of the leaders in horizontal drilling in the
Trend. From January 1, 1990 through June 30, 1996, the Company drilled or
participated in 223 gross (175.2 net) horizontal wells in the Trend.
The Company's operational focus for the remainder of 1996 and 1997 will be
the continued development of the North Giddings Block, which the Company has
assembled in the updip area of the Giddings Field in east central Texas. The
Company has accumulated approximately 109,000 net acres in the North Giddings
Block and is continuing to lease acreage in this area. The North Giddings Block
is located in the northern area of the Giddings Field in Burleson, Robertson and
Milam Counties, Texas, where the Austin Chalk formation is encountered at depths
ranging from 5,500 feet to 7,000 feet.
During the six months ended June 30, 1996, the Company added 1,718 MBOE of
estimated proved reserves through extensions and discoveries primarily in the
North Giddings Block. Reserve additions for the first six months of 1996 were
110% of production for the same period, while production for such period was
approximately the same on an MBOE basis as in the first six months of 1995. As
of June 30, 1996, the Company had 61.2 producing net wells in the North Giddings
Block and 76 additional drilling locations, of which seven are locations to
which proved undeveloped reserves are attributed by the Independent Engineers.
The Company believes, based on initial 2-D seismic surveys, that a portion
of the North Giddings Block is on-trend with the Cotton Valley pinnacle reef
play. Successful wells have been drilled in the Cotton Valley formation
approximately 24 miles northeast of the North Giddings Block. The Company has
planned the Cotton Valley Exploratory Project in three phases to explore for
potential reserves in this formation. The first phase is a proprietary 3-D
seismic survey covering portions of the North Giddings Block. The second phase
is the interpretation of the seismic data to delineate any drilling
opportunities in the Cotton Valley formation. The third phase would be the
exploratory drilling of any delineated prospects. To date, the Company has
committed to conduct a seismic survey covering approximately 20,000 acres in
Robertson County at a cost of approximately $3.1 million, including
interpretation. The Company anticipates that the survey will be completed during
the first quarter of 1997 and that the resulting data will be interpreted during
the second quarter of 1997. The Company may conduct additional surveys covering
other portions of the North Giddings Block. The Company's ability to drill any
delineated prospects will depend upon the availability of capital and other
factors that may be beyond its control. The Company's
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<PAGE>
current policy is to limit its annual Cotton Valley Exploratory Project
expenditures to not more than 25% of its planned annual capital expenditures.
However, the Company may modify this policy depending upon certain factors,
including the Company's financial position, exploratory drilling success,
technological advances, drilling activities conducted by third parties and
current and anticipated product prices. See "Risk Factors--Liquidity and Capital
Resources" and "--Risk of Exploratory Activities."
PRINCIPAL AREAS OF OPERATIONS
THE TREND. The Company's current production of oil and gas in the Trend is
derived principally from the Austin Chalk formation in the Giddings Field. At
June 30, 1996, the Company had interests in 214 gross (157.3 net) producing
wells in the Giddings Field, including 145 horizontal and 69 vertical wells. For
the six months ended June 30, 1996, the Company's daily net production in the
Giddings Field averaged approximately 5,242 Bbls of oil and 8,702 Mcf of gas.
The Company has drilled 15 wells in the Giddings Field during the first half of
1996, all of which were completed as productive wells. The Company operates 81%
of its wells in the Giddings Field.
Since May 1994, the Company has concentrated its Trend drilling activities
in the North Giddings Block. Wells producing from the Austin Chalk formation in
this updip portion of the Giddings Field are more prone to produce oil than gas.
The Company's current drilling technique in this area involves the drilling of
"dual stacked" lateral horizontal wells in the "A" and "B" zones of the Austin
Chalk formation. Dual stacked lateral wells involve the extension of horizontal
well bores in the same direction from the vertical extension of the well with
one lateral designed to penetrate the "A" zone and the other lateral designed to
penetrate the "B" zone. Currently, the combined length of the Company's dual
stacked horizontal laterals in this area ranges from 10,000 feet to 11,000 feet
per well and a completed dual stacked lateral well costs approximately $950,000,
excluding acreage costs.
As the Company's drilling activities in the North Giddings Block have moved
to the southwest, the Company has begun drilling, and may continue to drill,
"dual opposed" horizontal laterals, a drilling technique in which horizontal
laterals are drilled in opposite directions from the vertical extension of the
well with both laterals designed to penetrate the "A" zone, which is the deeper
of the two Austin Chalk zones. This technique has been designed to extend
horizontal laterals into the "B" zone at a date subsequent to initial
completion.
The Company also has production from the Pearsall area of the Trend, located
in south central Texas. The Company discontinued drilling activities in the
Pearsall area in 1993 and has no plans to resume drilling activities in this
area. For the six months ended June 30, 1996, the Company's daily net production
from wells located in the Pearsall area averaged approximately 432 Bbls of oil
and 551 Mcf of gas. The Company operates 98% of its wells in the Pearsall area.
The Company's wells in the Trend are routinely subjected to cyclic water
stimulation. Cyclic water stimulation involves pumping large volumes of water at
high injection rates into a well, shutting-in the well for ten days to two
weeks, and then returning the well to production. Water is pumped into the
reservoir in several stages and is absorbed into the micro-pore spaces of the
rock, thereby displacing oil into the fractures where it may be more readily
produced and, in some cases, extending the fracture system. The Company has used
the cyclic water stimulation method since 1987. The Company generally uses this
treatment technique during the well completion process and repeats the process
12 to 18 months after a well has been placed in production.
JALMAT FIELD. The Jalmat Field, which is located in Lea County, New Mexico,
was discovered in 1935. The Company has working interests in 132 gross (106.7
net) producing wells, all of which are operated by the Company and are located
on approximately 8,023 net acres. Following the Company's acquisition of the
Jalmat Field properties in 1988, a major recompletion and workover program was
commenced. This program included recompletion of both existing and temporarily
abandoned wells, and the use of hydraulic fracture stimulation on wells in the
Jalmat Field. Through June 30, 1996, 57 gross (46.1 net) gas wells have
26
<PAGE>
been successfully recompleted. For the six months ended June 30, 1996, the
Company's average daily production from this field was 117 Bbls of oil and 3,954
Mcf of gas.
Although the Company's long-term strategy in the Jalmat Field is to resume a
recompletion and workover program, no such activities have been undertaken in
1996. The Company has 23 proved recompletion or workover opportunities and 3
proved undeveloped drilling locations available to drill in the future.
Depending upon gas prices, the Company may conduct activities on certain of
these locations in 1997.
TEXAS GULF COAST. The Company owns interests in 26 gross (8.3 net) wells in
Wharton and Matagorda Counties in the Gulf Coast region of Texas. These wells
were acquired through two acquisitions in 1994 and are operated by third
parties. The Company's daily net production from this area during the six months
ended June 30, 1996 averaged approximately 85 Bbls of oil and 1,305 Mcf of gas.
COTTON VALLEY EXPLORATORY PROJECT
As the first phase of the Cotton Valley Exploratory Project, the Company
plans to initiate one or more 3-D seismic surveys during 1997 in its North
Giddings Block to determine if seismic features can be identified in the Cotton
Valley Haynesville formation at depths ranging from 15,000 to 16,000 feet
indicating the presence of pinnacle reef formations. The northern edge of the
North Giddings Block is approximately 24 miles southwest of the nearest current
Cotton Valley production. The presence of favorable 3-D seismic data provides no
assurance of success with respect to any subsequent drilling activities.
Approximately half of the wells drilled northeast of the North Giddings Block in
search of Cotton Valley pinnacle reefs have been productive. The Company
believes that all such wells have been drilled based on 3-D seismic surveys. The
Company estimates that a completed Cotton Valley pinnacle reef well would cost
at least $4,000,000. The Company's current policy is to limit its annual Cotton
Valley Exploratory Project expenditures to not more than 25% of its planned
annual capital expenditures. However, the Company may modify this policy
depending upon certain factors, including the Company's financial position,
exploratory drilling success, technological advances, drilling activities
conducted by third parties and current and anticipated product prices. See "Risk
Factors--Risk of Exploratory Activities."
PROVED RESERVES
The following table sets forth certain information as of June 30, 1996 with
respect to the Company's estimated proved oil and gas reserves and the present
value of estimated future net revenues therefrom (discounted at 10%).
<TABLE>
<CAPTION>
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
----------- ------------- ----------
<S> <C> <C> <C>
Oil (Mbbls)................................................................. 6,022 822 6,844
Gas (Mmcf).................................................................. 31,440 6,257 37,697
MBOE........................................................................ 11,262 1,865 13,127
Present value of estimated future net revenues (in thousands)............... $ 93,022 $ 7,319 $ 100,341
</TABLE>
The following table sets forth certain information as of June 30, 1996
regarding the Company's proved oil and gas reserves in each of its principal
producing areas.
<TABLE>
<CAPTION>
PROVED RESERVES PERCENTAGE OF
------------------------------------- PRESENT VALUE PRESENT VALUE OF
TOTAL OIL PERCENT OF OF FUTURE NET FUTURE NET
EQUIVALENT TOTAL OIL REVENUES BEFORE REVENUES BEFORE
AREA OR FIELD OIL (MBBLS) GAS (MMCF) (MBOE) EQUIVALENT INCOME TAXES INCOME TAXES
- ----------------------------------- ----------- ----------- ----------- ------------- --------------- ------------------
<S> <C> <C> <C> <C> <C> <C>
(IN THOUSANDS)
Trend.............................. 6,281 14,807 8,749 66.6% $ 75,837 75.6%
Jalmat............................. 320 15,323 2,874 21.9 14,910 14.9
Texas Gulf Coast................... 121 2,729 576 4.4 5,159 5.1
Other.............................. 122 4,838 928 7.1 4,435 4.4
----- ----------- ----------- ----- --------------- -----
Total.......................... 6,844 37,697 13,127 100.0% $ 100,341 100.0%
----- ----------- ----------- ----- --------------- -----
----- ----------- ----------- ----- --------------- -----
</TABLE>
27
<PAGE>
The estimates as of June 30, 1996 of proved reserves, future net revenues
from proved reserves and the present value of such future net revenues before
income taxes set forth in this Prospectus were based on a report prepared by the
Independent Engineers, a summary of which is included as Annex A. For purposes
of preparing such estimates, the Independent Engineers reviewed production data
through June 30, 1996 for properties representing 84% of the estimated present
value of the Company's proved developed producing reserves and through earlier
dates for the balance of the Company's properties. In order to calculate the
proved reserve estimates as of June 30, 1996, the Independent Engineers assumed
that production for each of the Company's properties since the date of the last
production data reviewed was in accordance with the production decline curve for
such property.
In accordance with applicable guidelines of the Commission, the estimates of
the Company's proved reserves and future net revenues therefrom set forth herein
are made using oil and gas sales prices estimated to be in effect as of the date
of such reserve estimates and are held constant throughout the life of the
properties. The weighted average of the sales prices utilized for the purposes
of estimating the Company's proved reserves and the future net revenues
therefrom as of June 30, 1996 were $20.10 per Bbl and $2.24 per Mcf of gas.
Estimated quantities of proved reserves and future net revenues therefrom are
affected by changes in oil and gas prices. Oil and gas prices have fluctuated
widely in recent years.
Also in accordance with Commission guidelines, the estimates of the
Company's proved reserves and future net revenues therefrom are made using
current lease and well operating costs estimated by the Company. Lease operating
expenses for oil wells operated by the Company in the Austin Chalk, Buda and
Georgetown formations were estimated using a combination of fixed and
variable-by-volume costs consistent with the Company's experience in operating
such wells. For purposes of calculating future net revenues and the discounted
present value therefrom, operating costs exclude accounting and administrative
overhead expenses attributable to the Company's working interest in wells
operated by it under joint operating agreements, but include administrative
costs associated with production offices. The present values of proved reserves
set forth herein should not be construed as the current market value of the
estimated proved oil and gas reserves attributable to the Company's properties.
See "Risk Factors-- Uncertainty of Estimates of Reserves and Future Net
Revenues."
EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company drilled, or participated in the drilling of, the following
numbers of wells during the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS
---------------------------------------- ENDED
JUNE 30,
1993 1994 1995 1996
------------ ------------ ------------ ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
DEVELOPMENT WELLS:
Oil....................................................... 22 17.9 14 11.7 24 21.0 15 12.7
Gas....................................................... 4 2.6 2 1.5 1 0.5 -- --
Dry....................................................... -- -- -- -- -- -- -- --
----- ---- ----- ---- ----- ---- ----- ----
Total................................................... 26 20.5 16 13.2 25 21.5 15 12.7
----- ---- ----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ---- ----- ----
EXPLORATORY WELLS:
Oil....................................................... 6 5.3 4 2.9 2 2.0 1 1.0
Gas....................................................... 2 1.1 1 1.0 -- -- -- --
Dry....................................................... 1 0.8 5 2.7 -- -- 2 .6
----- ---- ----- ---- ----- ---- ----- ----
Total................................................... 9 7.2 10 6.6 2 2.0 3 1.6
----- ---- ----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ---- ----- ----
TOTAL WELLS:
Oil....................................................... 28 23.2 18 14.6 26 23.0 16 13.7
Gas....................................................... 6 3.7 3 2.5 1 .5 -- --
Dry....................................................... 1 0.8 5 2.7 -- -- 2 .6
----- ---- ----- ---- ----- ---- ----- ----
Total................................................... 35 27.7 26 19.8 27 23.5 18 14.3
----- ---- ----- ---- ----- ---- ----- ----
----- ---- ----- ---- ----- ---- ----- ----
</TABLE>
28
<PAGE>
The information contained in the foregoing table should not be considered
indicative of future drilling performance, nor should it be assumed that there
is any necessary correlation between the number of productive wells drilled and
the amount of oil and gas that may ultimately be recovered by the Company.
The Company does not own any drilling rigs and all of its drilling
activities are conducted by independent contractors on a day rate basis under
standard drilling contracts. At June 30, 1996, the Company had two drilling rigs
under contract in the North Giddings Block, and plans to contract for a third
rig beginning in 1997.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the Company's
ownership as of June 30, 1996, of productive wells in the areas indicated.
<TABLE>
<CAPTION>
OIL GAS TOTAL
---------------------- ---------------------- -----------
GROSS NET GROSS NET GROSS
----------- --------- ----------- --------- -----------
<S> <C> <C> <C> <C> <C>
Trend........................................................... 246 185.3 21 15.5 267
Jalmat Area..................................................... 37 30.0 95 76.7 132
Texas Gulf Coast................................................ 1 .4 25 7.9 26
Other........................................................... 24 19.9 6 1.4 30
--- --------- --- --------- ---
Total....................................................... 308 235.6 147 101.5 455
--- --------- --- --------- ---
--- --------- --- --------- ---
<CAPTION>
NET
---------
<S> <C>
Trend........................................................... 200.8
Jalmat Area..................................................... 106.7
Texas Gulf Coast................................................ 8.3
Other........................................................... 21.3
---------
Total....................................................... 337.1
---------
---------
</TABLE>
The Company seeks to act as operator of the wells in which it owns a
significant interest. As operator of a well, the Company is able to manage
drilling and production operations as well as other matters affecting the
production and sale of oil and gas. In addition, the Company receives fees from
other working interest owners for the operation of the wells. At June 30, 1996,
the Company was the operator of 378 wells, or approximately 83% of the 455 total
wells in which it has a working interest. Production from those operated wells
represented approximately 91% of the Company's total net production for the six
months ended June 30, 1996.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes of, average sales prices received from, and average production costs
associated with the Company's sales of oil and gas for the periods indicated.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- --------------------
1993 1994 1995 1995 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
OIL AND GAS PRODUCTION DATA:
Oil (Mbbls)................................................... 1,881 1,709 1,831 1,376 1,601
Gas (Mmcf).................................................... 10,364 8,369 6,845 5,377 4,183
Total (MBOE).................................................. 3,608 3,104 2,972 2,272 2,298
AVERAGE OIL AND GAS SALES PRICES (1):
Oil ($/Bbl)................................................... $ 17.41 $ 15.72 $ 17.35 $ 17.40 $ 19.76
Gas ($/Mcf) (2)............................................... $ 2.15 $ 1.98 $ 1.77 $ 1.70 $ 2.48
AVERAGE PRODUCTION COSTS:
Lease operations ($/BOE) (3).................................. $ 3.54 $ 4.12 $ 4.55 $ 4.50 $ 4.70
</TABLE>
- ------------------------
(1) Includes effects of hedging transactions.
(2) Includes natural gas liquids.
(3) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.
29
<PAGE>
DEVELOPMENT, EXPLORATION AND ACQUISITIONS EXPENDITURES
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS
------------------------------- ENDED JUNE
1993 1994 1995 30, 1996
--------- --------- --------- -----------
<S> <C> <C> <C> <C>
(IN THOUSANDS)
Property Acquisitions:
Proved............................................................ $ -- $ 10,199 $ -- $ 1,246
Unproved.......................................................... 5,978 2,325 2,254 2,852
Developmental Costs................................................. 25,519 13,136 16,823 11,461
Exploratory Costs................................................... 11,219 5,699 1,407 1,167
--------- --------- --------- -----------
$ 42,716 $ 31,359 $ 20,484 $ 16,726
--------- --------- --------- -----------
--------- --------- --------- -----------
</TABLE>
ACREAGE
The following table sets forth certain information regarding the Company's
developed and undeveloped leasehold acreage as of June 30, 1996. Acreage in
which the Company's interest is limited to royalty, overriding royalty and
similar interests is excluded.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
-------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Trend........................................... 89,807 77,520 97,888 79,612 187,695 157,132
Jalmat Area..................................... 9,481 8,023 -- -- 9,481 8,023
Texas Gulf Coast................................ 8,617 3,922 562 163 9,179 4,085
Other........................................... 17,110 2,423 92,839 49,857 109,949 52,280
--------- --------- --------- --------- --------- ---------
Total......................................... 125,015 91,888 191,289 129,632 316,304 221,520
--------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- ---------
</TABLE>
MARKETS
GENERAL. The revenues generated from the Company's oil and gas operations
are highly dependent upon the prices of and the demand for its oil and gas
production. The prices received by the Company for its oil and gas production
depend upon numerous factors beyond the Company's control. Future decreases in
the prices of oil and gas could have an adverse effect on the Company's proved
reserves, revenues, profitability and cash flow. See "Risk Factors--Volatility
of Oil and Gas Prices." As a result of these factors, the Company engages in
price hedging activities from time to time. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Hedging
Transactions."
OIL SALES. Most oil purchasers periodically publish price bulletins to
inform producers of the base price for various grades and locations of crude
oil. These bulletins establish what is known in the oil and gas industry as the
"posted price." The posted price applicable to most of the Company's oil
production is generally $1 to $2 per barrel lower than the price quoted on the
NYMEX for spot West Texas Intermediate ("WTI") contracts since the oil purchaser
must bear the cost to physically gather, transport and store the purchased crude
oil.
The Company's oil production from the Trend is sold under three separate
contracts. The Giddings Field production from Burleson, Brazos and Robertson
Counties is primarily sold to Plains Marketing and Transportation, Inc.
("Plains"), under a contract which expires December 31, 1996, at a price based
on the average NYMEX price for WTI, less an agreed-upon deduction. The Giddings
Field production from Washington, Fayette and Lee Counties is sold to Plains,
under a contract which expires December 31, 1996 at a price based on the higher
of the average monthly posted price of Koch Oil Company or Pride Pipeline
Company, L.P. ("Pride"), plus an agreed-upon bonus. The Pearsall area production
is sold to Plains, under a contract which expires December 31, 1996, at a price
based on EOTT Energy Corp.'s monthly weighted average posted price for WTI, less
an agreed-upon deduction for sour oil, and plus an agreed-upon bonus for sweet
oil.
30
<PAGE>
Oil from the Jalmat Field is sold to Plains under a month-to-month contract.
This production is sold at a price equal to Pride's average monthly posted price
for WTI, less an agreed upon deduction.
GAS SALES. The Company is committed to sell substantially all of its gas
production from the Giddings Field to Aquila Southwest Pipeline Corporation
("Aquila") through September 1997. The predecessor to Aquila was formed in 1987
to acquire the assets of certain Predecessors engaged in the gas transmission
and processing businesses. In connection with the sale of such assets, certain
of the Predecessors dedicated certain gas production and processing rights with
respect to wells located in the Giddings Field and other area counties (the
"Dedicated Counties") to Aquila under terms which generally require Aquila to
match the best terms which the Company is able to obtain for its gas well gas
and to offer the best terms Aquila is offering for comparable quantities and
qualities of casinghead gas from the Dedicated Counties ("Dedication
Agreement"). The Dedication Agreement with respect to gas well gas produced from
the Dedicated Counties expires January 30, 1997.
As a result of the Dedication Agreement, the Company is a party to a gas
purchase contract dated October 1, 1991 with Aquila (the "Purchase Contract")
and has committed its gas to Aquila pursuant to a gas processing agreement (the
"Processing Agreement"). Both the Purchase Contract and the Processing Agreement
cover gas production from the Dedicated Counties. The term of the Purchase
Contract expires September 30, 1997. The prices received by the Company for gas
sold pursuant to the Purchase Contract and the Processing Agreement are based
upon formulae which are generally market responsive. The Company also has
reserved the right pursuant to the Purchase Contract to market its residue gas
to a third party.
Effective July 1, 1995, the Company began selling substantially all of its
gas production from the Jalmat Field to Sid Richardson Gasoline, Ltd.
("Richardson") under a contract which expires October 31, 2004. The price
received by the Company for residue gas sold pursuant to this contract is based
upon proceeds received by Richardson less a service fee and is generally market
responsive. The Company also shares in the proceeds received by Richardson for
liquids extracted from the Company's gas. Although the Company is currently
selling its residue gas to Richardson, it has the right to make sales to any
other third party.
A substantial portion of the Company's gas production from the Pearsall area
is sold to a subsidiary of the Company under two long-term contracts.
During 1995, Aquila purchased 52% and Richardson and its predecessor
combined to purchase 17% of the Company's gas production. If Aquila and
Richardson cease purchasing gas from the Company, the Company believes that it
would be able to replace such purchasers, although no assurance can be given as
to the prices it would be able to obtain from other parties; however, the loss
of Richardson as a purchaser in the Jalmat Field could result in curtailed
production due to the type of pipeline facilities otherwise available in the
area.
NATURAL GAS SERVICES
The Company owns an interest in and operates seven gas gathering systems and
three gas processing plants in the states of Texas and Mississippi. These
natural gas service facilities consist of interests in approximately 70 miles of
pipeline, two amine treating plants, one liquids extraction plant and three
compressor stations. The Company does not derive a significant portion of its
consolidated operating income from natural gas services and does not consider
this business to be a strategic part of its business plan.
COMPETITION AND MARKETS
Competition in all areas of the Company's operations is intense. Major and
independent oil and gas companies and oil and gas syndicates actively bid for
desirable oil and gas properties, as well as for the
31
<PAGE>
equipment and labor required to operate and develop such properties. A number of
the Company's competitors have financial resources and acquisition, exploration
and development budgets that are substantially greater than those of the
Company, which may adversely affect the Company's ability to compete with these
companies. Such companies may be able to pay more for productive oil and gas
properties and exploratory prospects and to define, evaluate, bid for and
purchase a greater number of properties and prospects than the Company's
financial or human resources permit.
The market for oil, gas and natural gas liquids produced by the Company
depends on factors beyond its control, including domestic and foreign political
conditions, the overall level of supply of and demand for oil, gas and natural
gas liquids, the price of imports of oil and gas, weather conditions, the price
and availability of alternative fuels, the proximity and capacity of gas
pipelines and other transportation facilities and overall economic conditions.
The oil and gas industry as a whole also competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
individual consumers.
REGULATION
The Company's oil and gas exploration, production and related operations are
subject to extensive rules and regulations promulgated by federal, state and
local agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and the
spacing, plugging and abandonment of such wells. The statutes and regulations of
certain states limit the rate at which oil and gas can be produced from the
Company's properties.
The Federal Energy Regulatory Commission ("FERC") regulates interstate
natural gas transportation rates and service conditions, which affect the
marketing of gas produced by the Company, as well as the revenues received by
the Company for sales of such production. Since the mid-1980s, the FERC has
issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B
("Order 636"), that have significantly altered the marketing and transportation
of gas. Order 636 mandates a fundamental restructuring of interstate pipeline
sales and transportation service, including the unbundling by interstate
pipelines of the sales, transportation, storage and other components of the
city-gate sales services such pipelines previously performed. One of the FERC's
purposes in issuing the orders is to increase competition within all phases of
the gas industry. Generally, Order 636 has eliminated or substantially increased
competition and volatility in natural gas markets. While significant regulatory
uncertainty remains, Order 636 may ultimately enhance the Company's ability to
market and transport its gas, although it may also subject the Company to
greater competition and more restrictive pipeline imbalance tolerances and
greater associated penalties for violation of such tolerances. Numerous parties
have filed petitions for review of Order 636, as well as orders in individual
pipeline restructuring proceedings. In July 1996, Order 636 was generally upheld
on appeal. The portions remanded for further action do not appear to materially
affect the Company. It is difficult to predict when all appeals of Order 636
will be completed or their impact on the Company.
The FERC has recently announced several important transportation-related
policy statements and proposed rule changes. In 1995, the FERC issued a policy
statement on how interstate natural gas pipelines can recover the costs of new
pipeline facilities. In January 1996, the FERC issued a policy
32
<PAGE>
statement and a request for comments concerning alternatives to its traditional
cost-of-service ratemaking methodology, including criteria to be used in
evaluating proposals to charge market-based rates for the transportation of
natural gas. In addition, the FERC recently issued a notice of proposed
rulemaking pursuant to which it proposes to substantially revise its regulations
regarding releases of firm interstate natural gas pipeline capacity. While any
resulting FERC action regarding these matters would affect the Company only
indirectly, the FERC's current rules and policy statements may have the effect
of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
trated materially differently than other natural gas producers and marketers
with which it competes.
Sales of oil and natural gas liquids by the Company are not regulated and
are made at market prices. The price the Company receives from the sale of those
products is affected by the cost of transporting the products to market.
Effective as of January 1, 1995, the FERC implemented regulations establishing
an indexing system for transportation rates for oil pipelines, which, generally,
would index such rate to inflation, subject to certain conditions and
limitations. These regulations could increase the cost of transporting oil and
natural gas liquids by pipeline, although the most recent adjustment generally
decreased rates. The Company is not able to predict with any certainty what
effect, if any, these regulations will have on it, but, other factors being
equal, the regulations may, over time, tend to increase transportation costs or
reduce wellhead prices for oil and natural gas liquids.
ENVIRONMENTAL MATTERS
Operations of the Company pertaining to oil and gas exploration, production
and related activities are subject to numerous and constantly changing federal,
state and local laws governing the discharge of materials into the environment
or otherwise relating to environmental protection. Numerous governmental
agencies issue regulations to implement and enforce such laws which are often
difficult and costly to comply with and which carry substantial civil and
criminal penalties for failure to comply. These laws and regulations may require
the acquisition of certain permits prior to or in connection with drilling
activities, restrict or prohibit the types, quantities and concentration of
substances that can be released into the environment in connection with drilling
and production, restrict or prohibit drilling activities that could impact
wetlands, endangered or threatened species or other protected areas or natural
resources, require some degree of remedial action to mitigate pollution from
former operations, such as pit cleanups and plugging abandoned wells, and impose
substantial liabilities for pollution resulting from the Company's operations.
Such laws and regulations may substantially increase the cost of exploring for,
developing, producing or processing oil and gas and may prevent or delay the
commencement or continuation of a given project and thus generally could have a
material adverse effect upon the capital expenditures, earnings, or competitive
position of the Company. Management of the Company believes it is in substantial
compliance with current applicable environmental laws and regulations, and the
cost of compliance with such laws and regulations has not been material and is
not expected to be material during the next fiscal year. Nevertheless, changes
in existing environmental laws and regulations or in the interpretations thereof
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. For instance, legislation has been
proposed in Congress from time to time that would reclassify certain oil and gas
production wastes as "hazardous wastes," which reclassification would make
exploration and production wastes subject to much more stringent handling,
disposal and clean-up requirements. State initiatives to further regulate the
disposal of oil and gas wastes and naturally occurring radioactive materials
could have a similar impact on the Company.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original
33
<PAGE>
conduct, on certain classes of persons that are considered to have contributed
to the release of a "hazardous substance" into the environment. These persons
include the owner or operator of the disposal site or the site where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances at the site where the release occurred. Under CERClA, such
persons may be subject to joint and several liability for the costs of cleaning
up the hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third paries to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment. The
Company is able to control directly the operation of only those wells with
respect to which it acts as operator. Notwithstanding the Company's lack of
direct control over wells operated by others, the failure of an operator other
than the Company to comply with applicable environmental regulations may, in
certain circumstances, be attributed to the Company. Management of the Company
believes that it has no material commitments for capital expenditures to comply
with existing environmental requirements.
The Oil Pollution Act ("OPA") imposes a variety of requirements on
"responsible parties" (E.G., owners, operators, lessees and permittees) for oil
and gas onshore and offshore facilities, pipelines, and vessels related to the
prevention of oil spills and imposes liability for damages resulting from such
spills in waters of the United States. OPA requirements include the assignment
of liability to each responsible party for oil spill removal costs and a variety
of public and private damages from oil spills, and the preparation of oil spill
contingency plans. Failure to comply with ongoing requirements or inadequate
cooperation in a spill event may subject a responsible party to civil or
criminal enforcement actions.
State water discharge regulations and federal waste discharge permitting
requirements adopted pursuant to the Federal Water Pollution Control Act
prohibit or are expected to prohibit within the next several months the
discharge of produced water and sand, and some other substances related to the
oil and gas industry, to coastal waters. Although the costs to comply with zero
discharge mandates under state or federal law may be significant, the entire
industry will experience similar costs and the Company believes that these costs
will not have a material adverse impact on the Company's financial conditions
and operations.
EMPLOYEES
At September 30, 1996, the Company had approximately 100 full-time
employees. None of the Company's employees is subject to a collective bargaining
agreement. The Company considers its relations with its employees to be good.
LEGAL PROCEEDINGS
The Company is a defendant in a suit styled THE STATE OF TEXAS, ET AL V.
UNION PACIFIC RESOURCES COMPANY ET AL, presently pending in Lee County, Texas.
The suit attempts to establish a class action consisting of unidentified royalty
and working interest owners throughout the State of Texas. Among other things,
the plaintiffs are seeking actual and exemplary damages for alleged violation of
various statutes relating to common carriers and common purchasers of crude oil
including discrimination in the purchase of oil by giving preferential treatment
to defendants' own oil and conspiring to keep the posted price or sales price of
oil below market value. A general denial has been filed. Because the Company is
neither a common purchaser nor common carrier of oil, management of the Company
believes there is no merit to the allegations as they relate to the Company or
its operations.
In addition, the Company is a defendant or codefendant in minor lawsuits
that have arisen in the ordinary course of business. While the outcome of these
lawsuits cannot be predicted with certainty, management does not expect any of
these to have a material adverse effect on the Company's consolidated financial
condition or results of operations.
34
<PAGE>
MANAGEMENT
The following are the members of the Company's Board of Directors and the
Company's executive officers:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ------------------------------------ ----- ---------------------------------------------------------------------
<S> <C> <C>
Clayton W. Williams, Jr............. 65 Chairman of the Board, President, Chief Executive Officer and a
Director
L. Paul Latham...................... 44 Executive Vice President, Chief Operating Officer and a Director
Mel G. Riggs........................ 41 Senior Vice President--Finance, Secretary, Treasurer, Chief Financial
Officer and a Director
Robert C. Lyon...................... 59 Vice President--Gas Gathering and Marketing
Patrick C. Reesby................... 44 Vice President--Acquisition/New Ventures
Jerry F. Groner..................... 34 Vice President--Land and Lease Administration
T. Mark Tisdale..................... 39 Vice President and General Counsel
Stanley S. Beard (1)(2)............. 56 Director
William P. Clements (1)(2).......... 79 Director
Robert L. Parker (1)(2)............. 73 Director
</TABLE>
- ------------------------
(1) Member of the Compensation Committee
(2) Member of the Audit Committee
Following are brief descriptions of the business experience of the Company's
directors and executive officers:
CLAYTON W. WILLIAMS, JR. has served as Chairman of the Board, President and
Chief Executive Officer and as a Director of the Company since September 1991.
Mr. Williams has been the Chief Executive Officer of the Williams Entities for
in excess of 15 years.
L. PAUL LATHAM is Executive Vice President, Chief Operating Officer and a
Director of the Company, having served in such capacities since September 1991.
Mr. Latham continues to serve as President of ClayDesta Corporation, a Williams
Entity engaged in real estate development and management.
MEL G. RIGGS has served as Senior Vice President--Finance, Secretary,
Treasurer, and Chief Financial Officer since 1991, and as a Director since 1994.
Mr. Riggs has served as manager of finance for various Williams Entities since
1989.
ROBERT C. LYON is Vice President--Gas Gathering and Marketing of the
Company. Mr. Lyon has been employed by the Company and its Predecessors since
1991.
PATRICK C. REESBY is Vice President--Acquisition/New Ventures of the
Company. He has been employed by the Company or its Predecessors since 1981.
JERRY F. GRONER is Vice President--Land and Lease Administration of the
Company. He has served as Manager of Land and Lease Administration since 1994.
Prior to 1994, he served as Associate General Counsel of the Company and its
Predecessors since 1990.
T. MARK TISDALE is Vice President and General Counsel of the Company. He has
been employed by the Company and its Predecessors since 1988.
STANLEY S. BEARD, is a Director of the Company and a member of the
Compensation and Audit Committees of the Board of Directors. Mr. Beard has been
an independent oil and gas operator for over
35
<PAGE>
twenty years, and has been a consultant to Mr. Williams periodically since 1968.
See "Certain Transactions and Relationships--Certain Contractual
Arrangements--Consulting Arrangements."
WILLIAM P. CLEMENTS is a Director of the Company and a member of the
Compensation and Audit Committees of the Board of Directors. Mr. Clements is a
former Governor of the State of Texas, having served two terms in such office
from 1979 to 1983 and from 1987 to 1991 and has been engaged in private
investments for more than the past five years.
ROBERT L. PARKER is a Director of the Company and a member of the
Compensation and Audit Committees of the Board of Directors. Mr. Parker has been
Chairman of the Board of Parker Drilling Company, a publicly-owned corporation
providing contract drilling services, for more than the past five years. He also
serves as a director of MAPCO, Inc., a diversified energy company, Weatherford-
Enterra Corporation, an international provider of specialized services and
products to the oil and gas industry, Bank of Oklahoma Financial Corp. and
Norwest Bank of Texas, Kerrville, N.A.
The following table sets forth the names, ages, titles and dates of
employment of certain other significant employees of the Company.
<TABLE>
<CAPTION>
EMPLOYED
NAME AGE POSITION SINCE
- ----------------------- --- -------------------------------- -----------
<S> <C> <C> <C>
D. Gregory Benton 34 Exploitation Manager 1990
Jeffrey R. Cummins 42 Drilling Manager 1981
David G. Grafe 34 Production Manager 1989
Mark B. Heinen 41 Acquisitions Manager 1993
Samuel L. Lyssy 34 Exploration Manager 1990
Ed Norwood 67 Team Leader Cotton Valley 1996
Michael L. Pollard 46 Controller 1993
</TABLE>
Prior to joining the Company in October 1996, Ed Norwood was an Advanced
Senior Geologist with Marathon Oil Company, and was involved in Marathon's
Cotton Valley pinnacle reef exploratory program.
36
<PAGE>
PRINCIPAL STOCKHOLDERS
The following table sets forth information as to the number and percentage
of shares of Common Stock owned beneficially as of November 6, 1996 by (i) each
person known to the Company to be the beneficial owner of more than 5% of the
Common Stock, (ii) certain of the Company's directors and executive officers,
and (iii) all directors and officers of the Company as a group. Unless otherwise
indicated in the footnotes following the table, the named beneficial owner had
sole voting and investment power over the shares of Common Stock shown as
beneficially owned by such beneficial owner.
<TABLE>
<CAPTION>
PERCENT OWNED
-----------------------------
NAME AND ADDRESS OF NUMBER OF BEFORE
BENEFICIAL OWNER SHARES OFFERING AFTER OFFERING
- ----------------------------------------------------------------------------- ---------- ------------ ---------------
<S> <C> <C> <C>
Clayton Williams Partnership, Ltd. (1)....................................... 3,772,009 50.3% 45.4%(10)
CWPLCO, Inc. (1)............................................................. 3,772,009 50.3% 45.4%(10)
Clayton W. Williams, Jr. (1) (2)............................................. 4,072,663 54.1% 48.7%(10)
Heartland Advisors, Inc. (3)................................................. 1,139,388 15.2% 13.0%
790 North Milwaukee Street
Milwaukee, WI 53202
Metropolitan Life Insurance Company.......................................... 556,168 7.4% 6.4%
One Madison Avenue
New York, NY 10010
State Street Research & Management Company (4)............................... 528,412 7.1% 6.0%
One Financial Center, 30th Floor
Boston, MA 02111-2690
L. Paul Latham (5)........................................................... 12,661 * *
Mel G. Riggs (6)............................................................. 11,437 * *
Stanley S. Beard (7)......................................................... 12,171 * *
William P. Clements (7)...................................................... 10,269 * *
Robert L. Parker (7)......................................................... 12,710 * *
T. Mark Tisdale (8).......................................................... 6,180 * *
All officers and directors as a group (10 persons) (9)....................... 4,159,079 54.9% 49.4%(10)
</TABLE>
- ------------------------
* Less than 1% of shares outstanding.
(1) The mailing address of Clayton Williams Partnership, Ltd., CWPLCO, Inc. and
Mr. Williams is Six Desta Drive, Suite 3000, Midland, Texas 79705. CWPLCO,
Inc. is the sole general partner of Clayton Williams Partnership, Ltd. Mr.
Williams shares voting and investment power with respect to the shares owned
by Clayton Williams Partnership, Ltd. and CWPLCO, Inc. The Company granted
Clayton Williams Partnership, Ltd. ("CWPL") and CWPLCO, Inc. certain
"piggy-back" registration rights with respect to the shares of Common Stock
each entity received in connection with the Consolidation. Whenever the
Company proposes to register any of its securities under the Securities Act
(other than registrations in connection with stock option plans and certain
other registrations) each of CWPL and CWPLCO may require the Company,
subject to certain limitations, to include all or any portion of such shares
of Common Stock in any such registrations. CWPL and CWPLCO have each waived
their registration rights in connection with this Offering.
(2) Includes (a) an aggregate of 3,772,009 shares owned of record by Clayton
Williams Partnership, Ltd. and CWPLCO, Inc. and beneficially owned by Mr.
Williams due to Mr. Williams' control of Clayton Williams Partnership, Ltd.
and CWPLCO, Inc., (b) 4,008 shares owned by Mr. Williams' spouse, (c) 588
shares owned by an estate administered by Mr. William's spouse, (d) 209,725
shares owned
37
<PAGE>
directly by Mr. Williams (including 4,679 shares held in the Company's
401(k) Plan & Trust over which Mr. Williams exercises investment control),
(e) 12,594 shares owned by three of Mr. Williams' children residing with
him, (f) 49,434 shares in Trusts of which Mr. Williams is the Trustee and
(g) the right to acquire beneficial ownership through presently exercisable
options to purchase 24,305 shares of Common Stock granted under the 1993
Stock Compensation Plan at an option price of $2.375 per share.
(3) Represents shares owned by clients of Heartland Advisors, Inc.
(4) Represents shares owned by clients of State Street Research & Management
Company.
(5) Includes (a) 2,895 shares owned directly by Mr. Latham (including 212 shares
held in the Company's 401(k) Plan & Trust which Mr. Latham exercises
investment control) and (b) the right to acquire beneficial ownership
through presently exercisable options to purchase 9,766 shares of Common
Stock granted under the 1993 Stock Compensation Plan at an option price of
$2.375 per share.
(6) Includes (a) 2,852 shares owned directly by Mr. Riggs (including 162 shares
held in the Company's 401(k) Plan & Trust over which Mr. Riggs exercises
investment control), (b) 1,382 shares over which Mr. Riggs exercises control
under a Power of Attorney and (c) the right to acquire beneficial ownership
through presently exercisable options to purchase 7,203 shares of Common
Stock granted under the 1993 Stock Compensation Plan at an option price of
$2.375 per share.
(7) Includes, in the case of Messrs. Beard, Clements and Parker, the right to
acquire beneficial ownership through presently exercisable options to
purchase (i) 1,000 shares each of Common Stock granted under the outside
Directors Stock Option Plan at an option price of $15.75 per share, (ii)
1,000 shares each of Common Stock granted under the Outside Directors Stock
Option Plan at an option price of $7.25 per share, (iii) 1,000 shares each
of Common Stock granted under the Outside Directors Stock Option Plan at an
option price of $5.50 per share and (iv) 1,000 shares each of Common Stock
granted under the Outside Directors Stock Option Plan at an option price of
$3.25 per share.
(8) Includes (a) 3,030 shares owned directly by Mr. Tisdale (including 2,271
shares held in the Company's 401(k) Plan & Trust over which Mr. Tisdale
exercises investment control) and (b) the right to acquire beneficial
ownership through presently exercisable options to purchase 3,150 shares of
Common Stock granted under the 1993 Stock Compensation Plan at an option
price of $2.375 per share.
(9) Includes all rights of directors and executive officers to acquire
beneficial ownership through presently exercisable options to purchase
shares of Common Stock granted under the Outside Directors Stock Option Plan
and the 1993 Stock Compensation Plan.
(10) Calculated based upon the aggregate of the number of shares beneficially
owned as of November 6, 1996 plus the 200,000 shares reserved to be offered
to Clayton Williams Partnership, Ltd. in the Offering.
CERTAIN TRANSACTIONS AND RELATIONSHIPS
THE CONSOLIDATION
The Company was formed to consolidate and continue certain operations
previously conducted by the Predecessors, which are controlled by Mr. Williams.
Concurrent with the completion of the Company's initial public offering, certain
of the operations of the Predecessors were consolidated, and the Company
succeeded to the oil and gas properties, exploration and development operations
and the natural gas gathering and marketing operations of the Predecessors,
except for the Excluded Properties.
In connection with the Consolidation, 3,200,000 shares of Common Stock were
issued to the predecessors of certain of the Affiliated Holders in exchange for
oil and gas properties, gas gathering
38
<PAGE>
facilities and other assets transferred to the Company by the Predecessors. The
predecessors of such Affiliated Holders disposed of 325,000 of such shares in
the initial public offering.
CERTAIN CONTRACTUAL ARRANGEMENTS
SERVICE AGREEMENT. The Company and the Williams Entities are parties to an
agreement (the "Service Agreement") pursuant to which the Company furnishes
services to, and receives services from, such entities. Under the Agreement, the
Company provides general accounting services, legal services, payroll and
benefits services and aircraft usage to the Williams Entities, as well as lease
operating and technical services with respect to the Excluded Properties. The
Williams Entities provide tax preparation and planning services to the Company.
The Company believes that these services can be performed on a more economical
basis through the use of shared personnel than by the establishment of separate
facilities. The recipient of a service is obligated to reimburse the provider
for the salary and benefit expenses incurred in providing such service and the
allocable portion of its associated general and administrative expenses. In
general, charges for personnel under the Service Agreement are made on a per
hour basis except that the Williams Entities are not required to pay in excess
of $50,000 per year for general accounting services and the Company is not
required to pay in excess of $40,000 per year for tax services. The obligation
to provide such services may be canceled by the Company or any of the Williams
Entities upon notice periods ranging from 30 days to 180 days. The Service
Agreement also allows for the Company and the Williams Entities to maintain
certain joint insurance coverage, including term life, medical and disability
insurance. The cost of such insurance is allocated among the parties on a cost
per employee basis which the Company believes to be reasonable. In addition, the
Service Agreement provides for the sharing of computer usage, which arrangement
can be canceled by the Company or the Williams Entities upon 180 days' notice.
Each party is entitled under the Service Agreement to audit the books and
records of any other party to ensure that charges made thereunder are proper and
to submit any dispute to arbitration by an independent third party. In general,
the Company does not provide to or obtain from unaffiliated third parties most
categories of services covered by the Service Agreement and it is not known upon
what terms such services would be available from, or made available to, such
parties. However, to the extent that the Company has provided services to the
Williams Entities at cost under the Service Agreement, the Company believes that
the terms upon which it has provided such services may be less favorable than
the terms the Company could have negotiated with unaffiliated third parties.
Conversely, to the extent that the Company has received services from the
Williams Entities at cost under the Service Agreement, the Company believes that
the terms upon which such services were available to the Company may be more
favorable than the terms the Company could have negotiated with unaffiliated
third parties. During 1995, the Williams Entities paid the Company approximately
$772,000, while the Company paid the Williams Entities approximately $16,000,
both pursuant to the Service Agreement.
OFFICE LEASE. The Company leases approximately 40,000 square feet of office
space in ClayDesta Center in Midland, Texas, pursuant to lease agreements
expiring at dates not later than November 1998. The building was owned by
ClayDesta Corporation until August 15, 1995. The Company continues to sublease
7,164 square feet from ClayDesta pursuant to an agreement which expires November
15, 1998. The Company believes each lease agreement is on terms not less
favorable than those generally available to unaffiliated parties for comparable
office space in the building.
GAS GATHERING MATTERS. Robert C. Lyon, Vice President Gathering and
Marketing, has a five percent net profits interest with respect to the presently
owned and future acquired gas gathering systems of the Company. Generally, the
Company's net profits from their gas gathering systems are computed in
accordance with generally accepted accounting principles, except that the
Company may charge against such profits an amount equal to its cost of funds on
its net fixed assets after depreciation. If Mr. Lyon leaves the employment of
the Company for any reason other than being discharged for cause, his net
profits interest is reduced to 1.5 percent and terminates seven years after the
cessation of his employment. In addition, Mr. Lyon also has the right to acquire
10 percent of the gas plants and systems of the Company
39
<PAGE>
by paying 10 percent of the acquisition and construction costs concurrently with
the Company payment of such costs. During 1995, the Company sold its interest in
two gas gathering and processing systems. Mr. Lyon owned a direct ownership
interest in one of the systems pursuant to his right to acquire 10 percent of
the Company's interest in such system. As a result, Mr. Lyon received $296,862
of sales proceeds in connection with this transaction. In addition, Mr. Lyon
received $364,597 pursuant to his net profits interest in 1995, of which
$311,915 related to the net profit realized by the Company and its Subsidiaries
from the sale of these systems.
CONSULTING AGREEMENTS. Stanley S. Beard, a Director of the Company and a
member of the Compensation and Audit Committees, served as a consultant to the
Company in connection with the disposition of certain properties previously
acquired by the Company in connection with its 3-D seismic exploration efforts
which were undertaken primarily in 1994. Mr. Beard received a monthly consulting
fee of $3,000, plus reimbursements of out-of-pocket expenses, for such services.
In total, Mr. Beard received $38,668 in consulting fees and expense
reimbursements during 1995. The consulting arrangements with Mr. Beard were
terminated in January 1996.
LOVING COUNTY PARTNERSHIP AGREEMENT. The Company entered into a partnership
effective in October 1995, (the "Partnership") with the Williams Entities for
the purpose of owning and operating certain wells and a gas treating plant
located in Loving County, Texas. Previous to the creation of the Partnership the
Company, along with Ellersly, Inc. ("Ellersly"), a company owned by Mr. Lyon
(the "Plant Owners"), owned the Mentone gas plant which is a gas treating
facility and associated pipeline of approximately seven miles in length (the
"Plant"). The Williams Entities owned interests in the Gataga 5-A well and the
Gataga 2-A well (collectively, the "Gataga Wells"). The Gataga Wells were
designated as Excluded Properties at the time of the Company's initial public
offering. The gas produced from the Gataga Wells must be treated in order to
render the gas marketable. The Plant treats gas from the Gataga Wells and one
other well, but is primarily dependent on the Gataga 5-A well in order to remain
economically viable. In 1995, a tubing leak was discovered in the Gataga 5-A
which jeopardized the continued long-term production from the well and,
correspondingly, the economic viability of the Plant. Due to the projected high
cost of repairing the tubing leak and the cause thereof, the Williams Entities
were not prepared to undertake such costs. Because the economic viability of the
Plant and the Gataga 5-A are dependent on one another, the Company and the
Williams Entities determined that it was in their best interest to enter into
the Partnership in order to protect the respective values of these assets. The
Plant Owners contributed all their interests in the Plant and the Williams
Entities contributed their interest in the Gataga Wells to the Partnership.
Currently, the Partnership provides for an allocation of revenues and expenses
of 50 percent to the well owners, 45 percent to the Company and 5 percent to
Ellersly. In reliance upon the opinion of an independent third party gas
industry expert that the terms of the Partnership are fair and reasonable to
both the Company and the Williams Entities, the creation of the Partnership and
the terms of the Agreement were approved by the Company's outside directors.
ACQUISITION OF OIL AND GAS INTERESTS. From time to time, the Company may
offer its employees, including its officers, the opportunity to participate with
the Company in acquisition and drilling activities on selected prospects. The
Company may authorize certain employees to purchase an interest in prospects to
be drilled or acquired by the Company, by paying the Company their pro rata
percentage of acquisition and drilling and completion costs (including costs
incurred by the Company prior to the date an interest is purchased by an
employee) on the same terms and conditions as the Company. In no instances will
such employee participation in the aggregate exceed 10% of the Company's
interest in a particular prospect. Any grant to any employee of the Company of
the opportunity to purchase an interest in a prospect must be approved by the
Compensation Committee. In the period since inception of the Company, this
policy has only been implemented twice. In January 1996, 18 employees of the
Company (including 6 of the Company's officers) purchased an aggregate 8.75%
working interest in a drilling prospect in which the Company participated in
Karnes County, Texas. The total consideration paid by the Company's employees
was $12,724 ($4,362 of which was paid by the Company's officers). The sole well
drilled on the prospect
40
<PAGE>
resulted in a dry hole. In August 1996, one employee of the Company purchased an
undivided 2.50% interest in certain non-operated properties acquired by the
Company from Conoco, Inc. The employee paid $30,625 for his interest.
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 3,000,000 shares of
Preferred Stock, par value $.10 per share ("Preferred Stock"), and 15,000,000
shares of Common Stock, par value $.10 per share. Upon the completion of this
Offering, the issued and outstanding capital stock of the Company will consist
of 8,748,216 shares of Common Stock.
The following description of certain matters relating to the capital stock
of the Company is summary in nature and is qualified in its entirety by the
provisions of the Company's Certificate of Incorporation and Bylaws, copies of
which have been filed with the Commission.
COMMON STOCK
The holders of Common Stock are entitled to one vote per share on all
matters submitted to a vote of stockholders of the Company. In addition, such
holders are entitled to receive ratably such dividends, if any, as may be
declared from time to time by the Board of Directors out of funds legally
available therefor, subject to the payment of preferential dividends with
respect to any Preferred Stock that from time to time may be outstanding. In the
event of the dissolution, liquidation or wind-up of the Company, the holders of
Common Stock are entitled to share ratably in all assets remaining after payment
of all liabilities of the Company and subject to the prior distribution rights
of the holders of any Preferred Stock that may be outstanding at that time. The
holders of Common Stock do not have cumulative voting rights or preemptive or
other rights to acquire or subscribe for additional, unissued or treasury
shares. All outstanding shares of Common Stock are, and when issued, the shares
of Common Stock to be sold by the Company in this Offering will be, fully paid
and nonassessable.
PREFERRED STOCK
The Board of Directors has the authority to issue 3,000,000 shares of
Preferred Stock, in one or more series, and to fix the rights, preferences,
qualifications, privileges, limitations or restrictions of each such series
without any further vote or action by the stockholders, including the dividend
rights, dividend rate, conversation rights, voting rights, terms of redemption
(including sinking funds provisions), redemption price or prices, liquidation
preferences and the number of shares constituting any series or the designations
of such prices. No shares of Preferred Stock have ever been issued, and the
Company has no present plans to issue any Preferred Stock.
CERTAIN EFFECTS OF AUTHORIZED BUT UNISSUED STOCK
Upon the completion of this Offering, the Company's authorized but unissued
capital stock will consist of 3,000,000 shares of Preferred Stock and 6,251,784
shares of Common Stock. One of the effects of the existence of authorized but
unissued capital stock may be to enable the Board of Directors to render more
difficult or to discourage an attempt to obtain control of the Company by means
of a merger, tender offer, proxy contest or otherwise, and thereby to protect
the continuity of the Company's management. If, in the due exercise of its
fiduciary obligations, for example, the Board of Directors were to determine
that a takeover proposal was not in the Company's best interests, such shares
could be issued by the Board of Directors without stockholder approval in one or
more private offerings or other transactions that might prevent or render more
difficult or costly the completion of the takeover transaction by: (i) diluting
the voting or other rights of the proposed acquiror or insurgent stockholder or
stockholder group; (ii) creating a substantial voting block in institutional or
other hands that might undertake to support the position of the incumbent Board
of Directors; and (iii) effecting an acquisition that might complicate or
preclude the
41
<PAGE>
takeover, or otherwise. In this regard, the Company's Certificate of
Incorporation grants the Board of Directors broad power to establish the rights
and preferences of the authorized and unissued Preferred Stock, one or more
series of which could be issued entitling holders to vote separately as a class
on any proposed merger or consolidation, to convert Preferred Stock into a
larger number of shares of Common Stock or other securities, to demand
redemption at a specified price under prescribed circumstances related to a
change in control, or to exercise other rights designed to impede a takeover.
The issuance of shares of Preferred Stock pursuant to the Board's authority
described above could decrease the amount of earning and assets available for
distribution to holders of Common Stock, and adversely affect the rights and
powers, including voting rights, of such holders and may have the effect of
delaying, deferring or preventing a change in control of the Company. The Board
of Directors does not currently intend to seek stockholder approval prior to any
issuance of authorized but unissued stock, unless otherwise required by law.
CERTIFICATE OF INCORPORATION AND BYLAWS
Under Delaware law, the exclusive power to adopt, amend and repeal bylaws is
conferred solely upon the stockholder unless the corporation's certificate of
incorporation also confers such power upon its Board of Directors. Under the
Company's Certificate of Incorporation, the Board of Directors has been granted
this power. The Certificate of Incorporation and the Company's Bylaws also
provide that (i) the number of directors shall be fixed from time to time by
resolution of the Board of Directors and (ii) the directors shall be divided
into three classes, with all directors in each class serving staggered terms of
three years each or until their respective successors are elected and qualified.
These provisions, in addition to the existence of authorized but unissued
capital stock, may have the effect, either alone or in combination with each
other, of making more difficult or discouraging an acquisition of the Company
deemed undesirable by the Board of Directors.
The Company's Board of Directors is currently comprised of six directors,
each of whom has one vote on each matter for which directors are entitled to
vote. The Bylaws provide that the Board has the power to decrease the number of
directors to one and increase the number of directors up to 15 persons, except
that no reduction in the number of directors shall have the effect of shortening
the term of any incumbent director. See "Management--Directors and Executive
Officers."
DELAWARE TAKEOVER STATUTE
The Company is subject to Section 203 of the Delaware General Corporation
Law. In general, Section 203 prevents an "interested stockholder" from engaging
in a "business combination" with a Delaware corporation for three years
following the date such person became an interested stockholder, unless (i)
prior to the date such person became an interested stockholder, the board of
directors of the corporation approved either the business combination or the
transaction which resulted in the interested stockholder becoming an interested
stockholder; (ii) upon consummation of the transaction that resulted in the
interested stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of the voting stock of the corporation
outstanding at the time the transaction commenced (excluding stock held (x) by
directors who are also officers of the corporation and (y) by employee stock
plans that do not provide employees with the rights to determine confidentially
whether shares held subject to the plan will be tendered in a tender or exchange
offer); or (iii) on or subsequent to the date of the transaction in which such
person became an interested stockholder, the business combination is approved by
the board of directors of the corporation and authorized at a meeting of the
stockholders by affirmative vote of the holders of two-thirds of the outstanding
voting stock of the corporation not owned by the interested stockholder. Under
Section 203, the restrictions described above do not apply to certain business
combinations proposed by an interested stockholder following the announcement or
notification of one of a number of extraordinary transactions involving the
corporation and a person who had not been an interested stockholder during the
previous three years or who became an interested stockholder with
42
<PAGE>
the approval of a majority of the directors, if such extraordinary transaction
is approved or not approved by a majority of the directors who were directors
prior to any person becoming an interested stockholder during the previous three
years or who were recommended for election or elected to succeed such directors
by a majority of such directors.
Section 203 defines a "business combination" to include (i) any merger or
consolidation involving the corporation and an interested stockholder, (ii) any
sale, lease, exchange, mortgage, pledge, transfer or other disposition involving
an interested stockholder of 10% or more of assets of the corporation, (iii)
subject to certain exceptions, any transaction which results in the issuance or
transfer by the corporation of any stock of the corporation to an interested
stockholder, (iv) any transaction involving the corporation which has the effect
of increasing the proportionate share of the stock of any class or series of the
corporations beneficially owned by the interested stockholder or (v) the receipt
by an interested stockholder of any loans, advances, guarantees, pledges or
other financial benefits provided by or through the corporation. In addition,
Section 203 defines an "interested stockholder" as any entity or person
beneficially owning 15% or more of the outstanding stock of the corporation and
any entity or person affiliated with or controlling or controlled by such an
entity or person.
STOCKHOLDER REPORTS
The Company furnishes to its stockholders annual reports containing audited
financial statements reported on by the independent public accountants for each
fiscal year.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Stock is Registrar and
Transfer Company, 10 Commerce Drive, Cranford, New Jersey 07016.
43
<PAGE>
UNDERWRITING
The Underwriters named below have severally agreed, subject to terms and
conditions contained in the Underwriting Agreement, to purchase from the Company
the respective number of shares of Common Stock set forth opposite their names.
<TABLE>
<CAPTION>
UNDERWRITER NUMBER OF SHARES
- --------------------------------------------------------------------------- -----------------
<S> <C>
Rodman & Renshaw, Inc...................................................... 625,000
Hanifen, Imhoff Inc........................................................ 625,000
-----------------
Total.................................................................... 1,250,000
-----------------
-----------------
</TABLE>
The Underwriting Agreement provides that the obligations of the several
Underwriters thereunder are subject to approval of certain legal matters by
counsel and to various other considerations. The nature of the Underwriters'
obligations is such that they are committed to purchase and pay for all of the
above shares of Common Stock if any are purchased.
The Underwriters have advised the Company that they propose to offer the
Common Stock initially at the public offering price set forth on the cover page
of this Prospectus; that the Underwriters may allow to selected dealers a
concession of $0.46 per share; and that such dealers may reallow a concession of
$0.10 per share to certain other dealers. After the public offering, the
offering price and other selling terms may be changed by the Underwriters. The
Common Stock is included for quotation on the Nasdaq National Market.
The Company has granted to the Underwriters a 30-day over-allotment option
to purchase up to an aggregate of 187,500 additional shares of Common Stock,
exercisable at the public offering price less the underwriting discount. If the
Underwriters exercise such over-allotment option, then each of the Underwriters
will have a firm commitment, subject to certain conditions, to purchase
approximately the same percentage thereof as the number of shares of Common
Stock to be purchased by it as shown in the above table bears to the 1,250,000
shares of Common Stock offered hereby. The Underwriters may exercise such option
only to cover over-allotments made in connection with the sale of the shares of
Common Stock offered hereby.
The Company, the officers and directors of the Company and certain
stockholders of the Company have agreed that they will not sell or dispose of
any shares of the Common Stock of the Company for a period of 180 days after the
later of the date on which the Registration Statement is declared effective by
the Commission or the first date on which the shares are bona fide offered to
the public, without the written consent of the Underwriters, other than
issuances or dispositions by the Company pursuant to certain existing employee
benefit plans.
The Company has agreed to indemnify the Underwriters against certain
liabilities, losses and expenses, including liabilities under the Securities
Act, or to contribute to payments that the Underwriters may be required to make
in respect thereof.
In connection with the Offering, certain Underwriters and selling group
members (if any) or their respective affiliates who are qualified registered
market makers on the Nasdaq National Market may engage in passive market making
transactions in the Common Stock on the Nasdaq National Market in accordance
with Rule 10b-6A under the Securities Exchange Act of 1934 (the "Exchange Act"),
during a specified period before commencement of offers or sales of the Common
Stock. The passive market making transactions must comply with applicable volume
and price limits and be identified as such. In general, a passive market maker
may display its bid at a price not in excess of the highest independent bid for
such security; if all independent bids are lowered below the passive market
maker's bid, however, such bid must then be lowered when certain purchase limits
are exceeded.
44
<PAGE>
The Underwriters are reserving an aggregate of 200,000 shares of Common
Stock to be offered at the public offering price set forth on the cover page of
this Prospectus to Clayton Williams Partnership, Ltd., a limited partnership
controlled by Clayton W. Williams, Jr., Chairman of the Board, President and
Chief Executive Officer of the Company.
LEGAL MATTERS
The validity of the issuance of the shares of Common Stock offered by this
Prospectus will be passed upon for the Company by Cotton, Bledsoe, Tighe &
Dawson, a Professional Corporation, Midland, Texas. Certain legal matters in
connection with the sale of such securities will be passed upon for the
Underwriters by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The audited Consolidated Financial Statements of Clayton Williams Energy,
Inc. and its subsidiaries included in this Prospectus and elsewhere in the
Registration Statement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their report with respect thereto, and are
included herein in reliance upon the authority of said firm as experts in giving
said report. Reference is made to said report, which includes an explanatory
paragraph with respect to the adoption of Statement of Financial Accounting
Standards No. 121, "Accounting for Impairment of Long-Lived Assets and Long-
Lived Assets to be Disposed Of" as discussed in Note 8 to the audited
Consolidated Financial Statements included elsewhere herein.
The estimates of proved reserves, estimated future net revenues and present
value thereof included in this Prospectus have been derived from the reports of
Williamson Petroleum Consultants, Inc., and all such information has been so
included in reliance on the authority of such firm as experts regarding the
matters contained in their reports.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith, files reports and other information with the Securities and Exchange
Commission (the "Commission"). Reports, proxy statements and other information
filed by the Company since May 1996 are available at the web site that the
Commission maintains at http:\www.sec.gov. and can be inspected and copied at
the public reference facilities maintained by the Commission at 450 Fifth
Street, N.W., Washington, D.C. 20549, and the Commission's Regional Offices at
Seven World Trade Center, 13th Floor, New York, New York 10048 and CitiCorp
Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511.
Copies of such material can be obtained by mail from the Public Reference Branch
of the Commission at 450 West Fifth Street, N.W., Washington, D.C. 20549, at
prescribed rates.
The Company has filed with the Commission a Registration Statement on Form
S-2 (herein, together with all amendments and exhibits, referred to as the
"Regulation Statement") under the Securities Act of 1933, as amended (the
"Securities Act"). This prospectus does not contain all of the information set
forth in the Registration Statement, certain parts of which were omitted in
accordance with the rules and regulations of the Commission. For further
information, reference is hereby made to the Registration Statement. Any
statements contained herein concerning the provisions of any document filed as
an exhibit to the Registration Statement or otherwise filed with the Commission
are not necessarily complete, and in each instance reference is made to the copy
of such document so filed. Each such statement is qualified in its entirety by
such reference.
45
<PAGE>
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
Incorporated by reference in this Prospectus are (i) the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1995, (ii) the
Company's Quarterly Reports on Form 10-Q for the quarters ended March 31, 1996,
June 30, 1996 and September 30, 1996 (iii) the Company's Proxy Statement dated
May 15, 1996 and (iv) Information Statements dated June 20, 1996 and September
9, 1996 filed previously with the Commission pursuant to Section 13 of the
Exchange Act. Any statement contained in a document incorporated by reference
herein shall be deemed to be modified or superseded for purposes of this
Prospectus to the extent that a statement contained herein modifies or
supersedes such statement. Any statement so modified or superseded shall not be
deemed, except as so modified or superseded, to constitute a part of this
Prospectus.
The Company will provide without charge to each person, including any
beneficial owner of Common Stock, to whom a copy of this Prospectus has been
delivered, on the written or oral request of such person, a copy of any or all
of the foregoing documents incorporated by reference in this Prospectus, other
than exhibits to such documents unless such exhibits are specifically
incorporated by referenced into the information that this Prospectus
incorporates. Written or oral requests for such copies should be directed to Mel
G. Riggs, Secretary, Clayton Williams Energy, Inc., Six Desta Drive, Suite 6500,
Midland, Texas 79705 (telephone: (915) 682-6324).
46
<PAGE>
GLOSSARY OF TERMS
The terms defined in this section are used throughout this Prospectus.
BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
BCF. One billion cubic feet.
BOE. Equivalent barrels of oil. In reference to natural gas, natural gas
equivalents are determined using the ratio of six Mcf of natural gas to one Bbl
of crude oil, condensate or natural gas liquids.
BTU. One British thermal unit. The quantity of heat required to raise the
temperature of one pound of water one degree Fahrenheit.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
DRY WELL. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion of an oil or gas well.
EXPLORATORY WELL. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be,
in which a working interest is owned.
MBBL. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
MMBTU. One million Btu's.
MCF. One thousand cubic feet.
MMCF. One million cubic feet.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.
PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES OR PV-10 VALUE. The present
value of estimated future net revenues is an estimate of future net revenues
from a property at its acquisition date, at a specified date, after deducting
production and ad valorem taxes, future capital costs and operating expenses,
but before deducting federal income taxes. The future net revenues have been
discounted at an annual rate of 10% to determine their "present value." The
present value is shown to indicate the effect of time on the value of the
revenue stream and should not be construed as being the fair market value of the
properties. Estimates have been made using constant oil and natural gas prices
and operating costs at the specified date.
PRODUCTIVE WELL. A well that is producing oil or gas that is capable of
production.
PROVED DEVELOPED RESERVES. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
47
<PAGE>
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED RESERVES. Reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.
ROYALTY INTEREST. An interest in an oil and gas property entitling the
owner to a share of oil and gas production free of costs of production.
3-D SEISMIC. Advanced technology method of detecting underground structures
with the potential for accumulations of hydrocarbons identified by the
collection and measurement of the intensity and timing of sound waves
transmitted into the earth as they reflect back to the surface.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
WORKING INTEREST. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
48
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
AUDITED CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Public Accountants................................................................ F-2
Consolidated Balance Sheets as of December 31, 1994 and 1995............................................ F-3
Consolidated Statements of Operations for the Years Ended December 31, 1993, 1994 and 1995.............. F-4
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1993, 1994 and 1995.... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 1993, 1994 and 1995.............. F-6
Notes to Consolidated Financial Statements.............................................................. F-7
UNAUDITED INTERIM CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Balance Sheets as of December 31, 1995 and September 30, 1996.............................. F-19
Consolidated Statements of Operations for the Nine Months and the Three Months Ended September 30, 1995
and 1996.............................................................................................. F-20
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 1995 and 1996............. F-21
Notes to Consolidated Financial Statements.............................................................. F-22
</TABLE>
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Clayton Williams Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Clayton
Williams Energy, Inc. as of December 31, 1995 and 1994, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended December 31, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Clayton Williams Energy,
Inc. as of December 31, 1995 and 1994, and the results of its operations and
cash flows for each of the three years in the period ended December 31, 1995, in
conformity with generally accepted accounting principles.
As discussed in Note 8, effective October 1, 1995, the Company adopted
Statement of Financial Accounting Standards No. 121 "Accounting for Impairment
of Long-Lived Assets and Long-Lived Assets to Be Disposed Of."
ARTHUR ANDERSEN LLP
Dallas, Texas
March 8, 1996
F-2
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1994 1995
----------- -----------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents............................................................. $ 1,431 $ 1,303
Accounts receivable:
Trade, net.......................................................................... 2,696 1,184
Affiliates.......................................................................... 387 738
Oil and gas sales................................................................... 5,575 6,615
Inventory............................................................................. 836 505
Other................................................................................. 479 565
----------- -----------
11,404 10,910
----------- -----------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method..................................... 306,448 325,268
Natural gas gathering and processing systems.......................................... 9,583 6,951
Other................................................................................. 9,399 9,460
----------- -----------
325,430 341,679
Less accumulated depreciation, depletion and amortization............................. (225,239) (259,533)
----------- -----------
Property and equipment, net......................................................... 100,191 82,146
----------- -----------
OTHER ASSETS............................................................................ 151 105
----------- -----------
$ 111,746 $ 93,161
----------- -----------
----------- -----------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade............................................................................... $ 6,419 $ 6,911
Affiliates.......................................................................... 133 346
Oil and gas sales................................................................... 4,446 4,813
Current maturities of long-term debt.................................................. 11,556 11,509
Accrued liabilities and other......................................................... 1,119 1,048
----------- -----------
23,673 24,627
----------- -----------
LONG-TERM DEBT.......................................................................... 49,147 33,538
----------- -----------
COMMITMENTS AND CONTINGENCIES........................................................... -- --
----------- -----------
STOCKHOLDERS' EQUITY:
Common stock, par value $.10 per share; authorized--10,000,000 shares; issued and
outstanding--5,700,000 shares in 1994 and 7,409,664 shares in 1995.................. 570 741
Additional paid-in capital............................................................ 48,934 52,912
Retained deficit...................................................................... (10,578) (18,657)
----------- -----------
38,926 34,996
----------- -----------
$ 111,746 $ 93,161
----------- -----------
----------- -----------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1994 1995
--------- --------- ---------
<S> <C> <C> <C>
REVENUES
Oil and gas sales.............................................................. $ 55,041 $ 43,617 $ 43,883
Natural gas services........................................................... 4,554 5,868 5,388
--------- --------- ---------
Total revenues............................................................... 59,595 49,485 49,271
--------- --------- ---------
COSTS AND EXPENSES
Lease operations............................................................... 12,788 12,775 13,533
Exploration.................................................................... 6,198 7,139 1,555
Natural gas services........................................................... 2,518 3,510 3,714
Depreciation, depletion and amortization....................................... 26,751 25,248 25,110
Impairment of property and equipment........................................... -- -- 10,259
General and administrative..................................................... 6,876 5,659 3,708
--------- --------- ---------
Total costs and expenses..................................................... 55,131 54,331 57,879
--------- --------- ---------
Operating income (loss)...................................................... 4,464 (4,846) (8,608)
Interest expense............................................................... 4,003 4,461 5,493
Other income (expense)......................................................... 149 759 6,022
--------- --------- ---------
INCOME (LOSS) BEFORE INCOME TAXES................................................ 610 (8,548) (8,079)
--------- --------- ---------
INCOME TAX EXPENSE
Current........................................................................ -- -- --
Deferred....................................................................... -- -- --
Pro forma...................................................................... 207 -- --
--------- --------- ---------
Total income tax expense..................................................... 207 -- --
--------- --------- ---------
NET INCOME (LOSS)................................................................ $ 403 $ (8,548) $ (8,079)
--------- --------- ---------
--------- --------- ---------
Net income (loss) per common share............................................... $ .09 $ (1.50) $ (1.31)
--------- --------- ---------
--------- --------- ---------
Weighted average common shares outstanding....................................... 4,700 5,700 6,165
--------- --------- ---------
--------- --------- ---------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK
---------------------- ADDITIONAL
NO. OF PAR PAID-IN RETAINED OWNERS'
SHARES VALUE CAPITAL DEFICIT TOTAL EQUITY
----------- --------- ----------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, December 31, 1992........................ -- $ -- $ -- $ -- $ -- $ 8,852
Pre-Consolidation net income, before pro forma
income taxes..................................... -- -- -- -- -- 2,640
Issuance of stock in connection with the
Consolidation.................................... 3,200 320 11,172 -- 11,492 (11,492)
Sale of stock in connection with the Initial
Public Offering, net of offering costs........... 2,500 250 37,762 -- 38,012 --
Post-Consolidation net loss....................... -- -- -- (2,030) (2,030) --
----- --------- ----------- ---------- --------- ----------
BALANCE, December 31, 1993........................ 5,700 570 48,934 (2,030) 47,474 --
Net loss........................................ -- -- -- (8,548) (8,548) --
----- --------- ----------- ---------- --------- ----------
BALANCE, December 31, 1994........................ 5,700 570 48,934 (10,578) 38,926 --
Sale of stock through rights offering, net of
offering costs................................ 1,599 160 3,648 -- 3,808 --
Issuance of stock through compensation plans.... 111 11 330 -- 341 --
Net loss........................................ -- -- -- (8,079) (8,079) --
----- --------- ----------- ---------- --------- ----------
BALANCE, December 31, 1995........................ 7,410 $ 741 $ 52,912 $ (18,657) $ 34,996 $ --
----- --------- ----------- ---------- --------- ----------
----- --------- ----------- ---------- --------- ----------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1994 1995
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) before pro forma income taxes................................. $ 610 $ (8,548) $ (8,079)
Adjustments to reconcile net income (loss) to cash provided by operating
activities:
Depreciation, depletion and amortization...................................... 26,751 25,248 25,110
Impairment of property and equipment.......................................... -- -- 10,259
Exploration costs............................................................. 4,244 6,227 1,472
(Gain) loss on sales of property and equipment................................ (165) (11) (5,978)
Other......................................................................... -- -- 339
Changes in operating working capital:
Accounts receivable........................................................... 7,415 2,964 121
Accounts payable.............................................................. (8,031) (2,197) 737
Other......................................................................... (1,108) (11) 220
--------- --------- ---------
Net cash provided by operating activities................................... 29,716 23,672 24,201
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment........................................... (37,417) (35,330) (20,433)
Proceeds from sales of property and equipment................................. 1,502 880 7,950
--------- --------- ---------
Net cash used in investing activities....................................... (35,915) (34,450) (12,483)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt.................................................. 499 17,200 --
Repayments of long-term debt.................................................. (27,885) (5,942) (15,656)
Repayments of vendor financing................................................ (10,872) -- --
Proceeds from sale of common stock............................................ 38,012 -- 3,808
--------- --------- ---------
Net cash provided by (used in) financing activities......................... (246) 11,258 (11,846)
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.............................. (6,445) 480 (128)
CASH AND CASH EQUIVALENTS
Beginning of period............................................................. 7,396 951 1,431
--------- --------- ---------
End of period................................................................... $ 951 $ 1,431 $ 1,303
--------- --------- ---------
--------- --------- ---------
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized.............................. $ 3,879 $ 4,860 $ 5,613
--------- --------- ---------
--------- --------- ---------
Noncash investing and financing activities--
Additions to property and equipment financed by vendors....................... $ 4,137 $ -- $ --
--------- --------- ---------
--------- --------- ---------
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND PRESENTATION
Clayton Williams Energy, Inc. (the "Company"), a Delaware corporation, was
incorporated in September 1991 for the purpose of consolidating and continuing
certain operations previously conducted by affiliates of Clayton W. Williams,
Jr. ("Mr. Williams"). Concurrent with the completion of the initial public
offering of the Company's common stock (the "Initial Public Offering") on May
26, 1993, these operations were consolidated (the "Consolidation"), and the
Company succeeded to the oil and gas properties, exploration and development
operations and the natural gas gathering and marketing operations of Mr.
Williams and his affiliates, except for minor interests in certain producing
wells, certain undeveloped acreage and mineral interests located outside of the
Company's primary areas of operations and the stock of a company owned by
affiliates of Mr. Williams. The consolidated financial statements include the
historical amounts and results of operations associated with the assets and
liabilities consolidated, as well as the assets and liabilities of subsidiaries
which became wholly owned by the Company following the Consolidation.
The Company is primarily engaged in the exploration for and development and
production of oil and natural gas in South and East Texas, Southeastern New
Mexico and the Texas Gulf Coast.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ESTIMATES AND ASSUMPTIONS
The preparation of 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.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Clayton
Williams Energy, Inc. and its subsidiaries (collectively, the "Company"). The
Company accounts for its interests in joint ventures and partnerships (all of
which are undivided) using the proportionate consolidation method, whereby its
share of assets, liabilities, revenues and expenses are consolidated with other
operations. All significant intercompany transactions and balances associated
with the consolidated operations have been eliminated.
OIL AND GAS PROPERTIES
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. Sales proceeds from sales of
individual properties are credited to property costs. No gain or loss is
recognized until the entire amortization base is sold or abandoned.
Costs of acquisition of leaseholds are capitalized. Unproved oil and gas
properties with significant acquisition costs are periodically assessed and any
impairment in value is charged to exploration costs. 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. The costs of unproved properties which are determined to hold
proved reserves are transferred to proved oil and gas properties.
F-7
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 exploration expense if and when the well is determined to be
unsuccessful.
NATURAL GAS AND OTHER PROPERTY AND EQUIPMENT
Natural gas gathering and processing systems consist primarily of gas
gathering pipelines, compressors and gas processing plants. Other property and
equipment primarily consists of field buildings, office equipment, leasehold
improvements, vehicles and live oil systems. Major renewals and betterments are
capitalized while the costs of repairs and maintenance are charged to expense as
incurred. The costs of assets retired or otherwise disposed of and the
applicable accumulated depreciation are removed from the accounts, and any gain
or loss is included in the results of operations.
Depreciation of natural gas gathering and processing systems and other
property and equipment is computed on the straight-line method over the
estimated useful lives of the assets, which range from 3 to 32 years.
VALUATION OF PROPERTY AND EQUIPMENT
Effective October 1, 1995, the Company adopted the provisions of Statement
of Financial Accounting Standards No. 121 "Accounting for Impairment of
Long-Lived Assets" which requires that long-lived assets be assessed for
potential impairment in their carrying values when circumstances indicate such
impairment may have occurred. See Note 8 for the impact of adoption of SFAS 121
on the Company.
INVENTORY
Inventory consists primarily of tubular goods and other well equipment which
the Company plans to utilize in its ongoing exploration and development
activities and is carried at the lower of cost or market value.
CAPITALIZATION OF INTEREST
Interest costs associated with maintaining the Company's inventory of
unproved oil and gas properties are capitalized. Interest capitalized totaled
approximately $355,000, $192,000 and $85,000 for the years ended December 31,
1993, 1994 and 1995, respectively.
STATEMENTS OF CASH FLOWS
The Company considers all highly liquid investments with original maturities
of three months or less to be cash equivalents.
NET INCOME (LOSS) PER COMMON SHARE
Net income (loss) per common share is based on the weighted average number
of common and common equivalent shares, if dilutive, outstanding during each
period. Common stock equivalents were not included in the computation of net
income (loss) per share in 1993, 1994 or 1995 since the effect was
anti-dilutive.
F-8
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
REVENUE RECOGNITION AND GAS BALANCING
The Company utilizes the sales method of accounting for natural gas revenues
whereby revenues are recognized based on the amount of gas sold to purchasers.
The amount of gas sold may differ from the amount to which the Company is
entitled based on its revenue interests in the properties. The Company had no
significant imbalance positions at December 31, 1993, 1994 or 1995.
RECLASSIFICATIONS
Certain reclassifications of prior year financial statement amounts have
been made to conform to current year presentations.
3. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
--------- ---------
<S> <C> <C>
(IN THOUSANDS)
Secured Bank Credit Facility (matures July 31, 1998):
Revolving loan........................................................ $ 21,100 $ 17,000
Term loan............................................................. 39,225 27,825
Subordinated Debt Facility.............................................. -- --
Other................................................................... 378 222
--------- ---------
60,703 45,047
Less current maturities................................................. 11,556 11,509
--------- ---------
$ 49,147 $ 33,538
--------- ---------
--------- ---------
</TABLE>
Aggregate maturities of long-term debt at December 31, 1995 are as follows:
1996--$11,509,000; 1997--$11,513,000; and 1998--$22,025,000.
SECURED BANK CREDIT FACILITY
The Company's secured bank credit facility provides for a revolving loan
facility and a term loan facility, the limits of which are determined by a
borrowing base established by the banks. At December 31, 1995, the borrowing
base was $49.5 million, of which $21.7 million was attributable to the revolving
loan facility and $27.8 million was attributable to the term loan facility. The
amount of funds available on the revolving loan facility at December 31, 1995
was $4.7 million. The borrowing base is scheduled to be redetermined in May 1996
and at least semi-annually thereafter; however, the Company or the banks may
request a borrowing base redetermination at any other time during the year. Any
redetermination will be made at the discretion of the banks. If, at any time,
outstanding advances plus letters of credit exceed the borrowing base, 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 the facility 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
secured bank credit facility.
F-9
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT (CONTINUED)
The term loan facility presently requires monthly principal prepayments of
$950,000. The amount of monthly prepayments is subject to change at the time of
each borrowing base redetermination. No additional advances are permitted
against the term loan facility.
All outstanding balances on the secured bank credit facility may be
designated, at the Company's option, as either "Base Rate Loans" or "Eurodollar
Loans" (as defined in the agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans will bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 1/2% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans will bear interest at the LIBOR rate for a fixed period of time
elected by the Company plus a Eurodollar Margin ranging from 2% to 2.75% per
annum. At December 31, 1995, the Company's indebtedness under these facilities
consisted of $30.8 million of Base Rate Loans at 9% and $14 million of
Eurodollar Loans at 8.6%.
In addition, the Company pays the banks a commitment fee equal to 1/2% per
annum on the unused portion of the revolving loan commitment. Interest on the
revolving loan and fees are payable quarterly, and all outstanding principal and
interest will be due July 31, 1998.
SUBORDINATED DEBT FACILITY
In June 1995, the Company obtained a commitment from the Agent bank in its
secured bank credit facility to loan the Company up to $5.5 million under a
subordinated debt facility which provides for interest at a minimum rate of
14.25% per year, plus certain commitment fees, with interest payable monthly and
principal payable at maturity on July 31, 1998. The commitment originally
expired on December 31, 1995, but was extended to December 31, 1996. The entire
amount of the facility may be prepaid without penalty or premium at any time
prior to maturity, but only if the Company obtains the approval of the lenders
in the secured bank credit facility. The Company does not plan to utilize this
subordinated debt facility unless the funds available on the secured bank credit
facility are inadequate to finance the Company's planned capital expenditure
program in 1996.
4. SALE OF COMMON STOCK
In September 1995, the Company received $3,808,000, net of offering costs of
$93,000, from the sale of 1,598,971 shares of common stock at a price of $2.44
per share pursuant to a registered rights offering made to stockholders of
record on August 18, 1995. Proceeds from the offering were used to repay
indebtedness on the secured bank credit facility.
5. STOCK COMPENSATION PLANS
1993 PLAN
The Company has reserved 298,200 shares of common stock for issuance under
the 1993 Stock Compensation Plan ("1993 Plan"). The 1993 Plan provides for the
issuance of nonqualified stock options with an exercise price which is not less
than the market value of the Company's common stock on the date of grant. All
options granted to date vest 25% annually and expire seven years from date of
grant.
F-10
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. STOCK COMPENSATION PLANS (CONTINUED)
The following table reflects activity in the 1993 Plan for 1993, 1994 and
1995.
<TABLE>
<CAPTION>
1993 1994 1995
---------------------- ----------------------- -----------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- ----------- ---------- ----------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C>
Beginning of year............................. -- -- 276,937 $ 15.75 149,101 $ 7.25
Granted..................................... 276,937 $ 15.75 149,101 $ 7.25 149,101 $ 2.38
Forfeited................................... -- -- (33,785) $ 15.75 (18,540) $ 7.25
Cancelled (a)............................... -- -- (243,152) $ 15.75 (128,061) $ 7.25
--------- ---------- ----------
End of year................................... 276,937 $ 15.75 149,101 $ 7.25 151,601 $ 2.45
--------- ---------- ----------
--------- ---------- ----------
Exercisable................................... -- -- 37,275 $ 7.25 75,800 $ 2.45
--------- ---------- ----------
--------- ---------- ----------
Issuable...................................... 21,263 149,099 146,599
--------- ---------- ----------
--------- ---------- ----------
</TABLE>
- ------------------------
(a) During 1994, the Company offered participants the opportunity to exchange
options issued in 1993 at $15.75 per share for a lesser number of options
with an exercise price of $7.25 per share. In 1995, the Company offered to
exchange substantially all of the options issued in 1994 with an exercise
price of $7.25 per share for new options with an exercise price of $2.38 per
share.
DIRECTORS PLAN
The Company has reserved 86,300 shares of common stock for issuance under
the Outside Directors Stock Option Plan ("Directors Plan"). Since inception of
the Directors Plan, the Company has issued options covering 9,000 shares of
common stock (3,000 in 1993 at $15.75 per share, 3,000 in 1994 at $7.25 per
share, and 3,000 in 1995 at $5.50 per share). All options expire in 2000 and are
fully exercisable at date of grant. At December 31, 1995, options to purchase
9,000 shares were outstanding, and 77,300 shares remain available for future
grants.
BONUS INCENTIVE PLAN
The Company has reserved 115,500 shares of common stock for issuance under
the Bonus Incentive Plan. The plan provides that the Board of Directors each
year may award bonuses in cash, common stock of the Company, or a combination
thereof. To date, no bonuses in cash or stock have been awarded under this plan.
STOCK COMPENSATION PLANS
In May 1995, the Company's Board of Directors adopted two stock compensation
plans, one for selected officers and one for outside directors of the Company.
These plans permit the Company to pay all or part of selected executives'
salaries and all outside director's fees in shares of common stock in lieu of
cash. The Company has reserved an aggregate of 650,000 shares of common stock
for issuance under these plans. During 1995, the Company has issued Mr. Williams
101,663 shares of common stock in lieu of cash compensation aggregating
$312,000, and has issued 9,030 shares to three outside directors in lieu of cash
compensation aggregating $29,000. The amounts of such compensation are included
in general and administrative expense in the accompanying consolidated financial
statements.
F-11
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. TRANSACTIONS WITH AFFILIATES
During the periods presented, the Company and various entities controlled by
Mr. Williams provided certain general and administrative services to one
another. In connection with the Consolidation, the Company and the Williams
entities entered into a service agreement to standardize the procedures for
charging for such services. In addition, the Company leases office space from an
affiliate. General and administrative expenses in the accompanying financial
statements are net of charges by the Company to affiliates for services
aggregating $559,000, $855,000 and $772,000 for the years ended December 31,
1993, 1994 and 1995, respectively, and include charges to the Company by
affiliates for rents and services aggregating $636,000, $512,000 and $289,000
for the years ended December 31, 1993, 1994 and 1995, respectively.
Accounts receivable from affiliates and accounts payable to affiliates
include, among other things, amounts for charges whereby the Company is the
operator of certain wells in which affiliates own an interest. These charges are
on terms which are consistent with the terms offered to unaffiliated third
parties which own interests in wells operated by the Company.
At December 31, 1995, the Company owned a 90% interest in the Mentone gas
plant constructed in 1993 to process gas from two wells in Loving County, Texas
pursuant to a long-term contract. The two wells are substantially owned by
entities controlled by Mr. Williams. Because the plant and the wells are largely
dependent upon each other for their economic viability, the Company and the
entities controlled by Mr. Williams contributed their respective interests in
the plant and wells to a partnership effective January 1996. After recoupment of
certain workover costs by the well owners, the Company will own an undivided 45%
interest in the partnership, and will proportionately consolidate its share of
partnership income, expense, assets and liabilities.
7. COMMITMENTS AND CONTINGENCIES
LEASES
The Company leases office space from affiliates and nonaffiliates under
noncancelable operating leases. Rental expense pursuant to the office leases
amounted to $489,000, $489,000 and $453,000 for the years ended December 31,
1993, 1994 and 1995, respectively. Included in property and equipment are assets
under capital leases aggregating $648,000, $528,000 and $233,000 net of
accumulated depreciation, at December 31, 1993, 1994 and 1995, respectively.
Future minimum payments under noncancelable leases at December 31, 1995, are
as follows:
<TABLE>
<CAPTION>
CAPITAL OPERATING
LEASES LEASES
----------- -----------
<S> <C> <C>
(IN THOUSANDS)
1996............................................................................... $ 129 $ 534
1997............................................................................... 118 440
1998............................................................................... -- 88
----- -----------
Total minimum lease payments................................................... 247 $ 1,062
-----------
-----------
Less amount representing interest.................................................. (25)
-----
Present value of net minimum lease payments.................................... $ 222
-----
-----
</TABLE>
F-12
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. COMMITMENTS AND CONTINGENCIES (CONTINUED)
CONCENTRATION OF CREDIT RISK
The Company's revenues are derived principally from uncollateralized sales
to customers in the oil and gas industry. The concentration of credit risk in a
single industry affects the Company's overall exposure to credit risk because
customers may be similarly affected by changes in economic and other conditions.
The Company has not experienced significant credit losses on such receivables.
FORWARD SALES TRANSACTIONS
The Company accounts for forward sale and put option arrangements as hedging
activities and, accordingly, gains and losses are included in oil and gas
revenues in the period the hedged production is sold. Included in oil and gas
revenues are gains totaling $631,000 in 1993 and net losses totaling $78,000 in
1994 (comprised of losses of $238,000 partially offset by gains of $160,000) and
$342,000 in 1995 (comprised of losses of $426,000 partially offset by gains of
$84,000). In December 1995, the Company entered into a financial swap
arrangement covering the sale of 99,000 barrels of oil production from February
1996 through April 1996 at a price of $18.00 per Bbl. In January 1996, the
Company entered into a financial swap arrangement covering an additional 135,000
barrels of oil production from January 1996 through April 1996 at a weighted
average price of $19.37 per Bbl, ranging from a high of $20.09 to a low of
$18.67. In February 1996, the Company entered into a financial swap arrangement
covering the sale of 223,000 barrels of oil production from March 1996 through
August 1996 at a weighted average price of $18.48 per Bbl, ranging from a high
of $19.55 to a low of $17.75. In March 1996, the Company entered into a
financial swap arrangement covering the sale of 60,000 barrels of oil production
from April 1996 through June 1996 at a weighted average price of $18.46 per Bbl,
ranging from a high of $19.02 to a low of $17.99. In the aggregate, these hedge
transactions account for approximately 40% of the Company's expected oil
production from January 1996 through August 1996.
LEGAL PROCEEDINGS
In April 1994, the Fifth Circuit Court of Appeals reversed a judgment
against the Company for approximately $600,000 in damages. The case was settled
with no damages being assessed against the Company. Accordingly, the Company
reversed the previously recorded loss provision, resulting in the recognition of
$600,000 of other income during 1994.
The Company is involved in various legal proceedings arising in the normal
course of its business, including actions for which insurance coverage is
available. While the ultimate results of these proceedings cannot be predicted
with certainty, the Company does not believe that the outcome of any of these
matters will have, individually or in the aggregate, a material adverse effect
on its financial condition; however, they could have a material impact on
results of operations in an annual or interim period.
8. ADOPTION OF ACCOUNTING PRONOUNCEMENT
On March 31, 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 121, "Accounting for Impairment of
Long-Lived Assets" ("SFAS 121"). SFAS 121 requires entities to record an
impairment loss equal to the difference between the fair market value and the
carrying value of any asset (or group of assets) which is deemed to be impaired
in accordance with certain prescribed measurement criteria. Adoption of SFAS 121
is required for fiscal years beginning after December 15, 1995, although earlier
adoption is encouraged.
F-13
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. ADOPTION OF ACCOUNTING PRONOUNCEMENT (CONTINUED)
The Company elected to adopt SFAS 121 effective October 1, 1995, and as a
result, recorded a provision for impairment of property and equipment totaling
$10.3 million, of which $9.1 million related to proved oil and gas properties
and $1.2 million related to gas gathering and processing systems. Substantially
all of the impaired assets are located in the Pearsall Field of South Texas.
9. SALES OF ASSETS
In August 1995, XCEL Gas Company, a general partnership in which the Company
owns a 77% interest, sold its interest in a gas gathering system, and the
Company sold its 43% interest in the El Campo gas processing system, for
aggregate net proceeds of $7.7 million, resulting in a combined gain on sale of
property and equipment of $6.0 million, net to the Company. The Company used the
proceeds from these sales to repay indebtedness on the secured bank credit
facility.
The following table sets forth, on a pro forma basis, the results of
operations of the Company for the year ended December 31, 1995, as adjusted to
give effect to the sale of assets described above and the sale of common stock
discussed in Note 4.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1995
-------------------------
HISTORICAL PRO FORMA
------------ -----------
(DOLLARS IN THOUSANDS,
EXCEPT PER SHARE)
<S> <C> <C>
Revenues.................................................................... $ 49,271 $ 46,456
Operating loss.............................................................. $ (8,608) $ (9,061)
Net loss.................................................................... $ (8,079)(a) $ (13,449)
Net loss per common share................................................... $ (1.31)(a) $ (1.83)
</TABLE>
- ------------------------
(a) Includes gain on sale of gas gathering and processing assets of $5,960,000
($.81 per share).
In January 1996, the Company sold its rights to the Buda and Georgetown
formations under approximately 28,000 net acres in Robertson County, Texas for
$3.5 million. Certain leases covered by the sale must be extended during 1996,
and the Company estimates that it will be required to spend approximately
$600,000 in this effort. The Company also granted the purchaser the option to
acquire additional Buda and Georgetown rights under approximately 36,000 net
acres in Burleson County, Texas. The net proceeds were used to repay
indebtedness on the secured bank credit facility, resulting in an increase in
funds then available for borrowing of $2.9 million. No gain or loss was
recognized on the sale.
10. INCOME TAXES
Concurrent with the Consolidation on May 26, 1993 (see Note 1), the Company
adopted the provisions of Statement of Financial Accounting Standards No. 109
("SFAS 109"). Under the asset and liability method of SFAS 109, deferred tax
assets and liabilities are recognized for the future tax consequences
attributable to differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax bases. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are expected to
be recovered or settled. Under SFAS 109, the effect on deferred tax assets and
liabilities of a change in enacted tax rates is recognized in income in the
period that includes the enactment date.
F-14
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. INCOME TAXES (CONTINUED)
Prior to the Consolidation, the results of operations of the Company were
included in the tax returns of the owners of the affiliates of Mr. Williams. As
a result, tax strategies were implemented which were not reflective of the
strategies the Company would have implemented. As of the date of Consolidation,
financial statement carrying amounts of existing assets and liabilities were
approximately the same as their respective tax bases. Accordingly, no net
deferred tax assets or liabilities were recorded in connection with the
Consolidation. For periods prior to the Consolidation, a pro forma tax charge
was computed at the applicable federal statutory rate.
Since the Consolidation, the Company has incurred net losses for financial
reporting purposes aggregating $18.7 million and has recognized cumulative tax
losses of approximately $32 million which can be carried forward and used to
offset future taxable income. Tax loss carryforwards begin to expire in 2008.
Due to the uncertainty of realizing the related future tax benefits, valuation
allowances have been recorded to the extent net deferred tax assets exceed net
deferred tax liabilities at December 31, 1995 and 1994.
The tax effected temporary differences and tax loss carryforwards which
comprise net deferred tax assets and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1994 1995
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Deferred tax assets (liabilities):
Depreciable and depletable property............................................. $ (6,153) $ (4,030)
Tax loss carryforwards.......................................................... 10,533 11,305
Other........................................................................... 1,057 912
Valuation allowance............................................................. (5,437) (8,187)
--------- ---------
Net deferred tax asset (liability)............................................ $ -- $ --
--------- ---------
--------- ---------
</TABLE>
11. TERMINATION OF ARGENTINA VENTURE
During 1994, the Company conducted certain exploration activities in the
Colhue Huapi area of Argentina pursuant to an exploration agreement with CAPEX
S.A. This agreement obligated the Company to drill a minimum of six wells by
March 1, 1995, as extended, or pay a contract termination fee of $437,500 per
well for each well not drilled. The Company drilled two of the six obligation
wells, and based upon its evaluation of the drilling results, elected not to
drill any additional wells in the area. In February 1995, the Company sold its
entire interest in the Argentina venture to Occidental Petrolera de Argentina,
Ltd. for $100,000 and secured a release from all drilling commitments and
obligations under the original agreement, including any obligation to pay
termination fees. The 1994 results of operations include exploration costs of
$2,481,000 and general and administrative expenses of $601,000 attributable to
the Argentina venture. Results of operations in 1995 from this venture were
insignificant.
F-15
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. COSTS OF OIL AND GAS PROPERTIES
The following table sets forth certain information with respect to costs
incurred in connection with the Company's oil and gas producing activities:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1994 1995
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisitions:
Proved............................................................... $ -- $ 10,199 $ --
Unproved............................................................. 5,978 2,325 2,254
Developmental costs.................................................... 25,519 13,136 16,823
Exploratory costs...................................................... 11,219 5,699 1,407
--------- --------- ---------
$ 42,716 $ 31,359 $ 20,484
--------- --------- ---------
--------- --------- ---------
</TABLE>
The following table sets forth the capitalized costs for oil and gas
properties:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------
1994 1995
---------- -----------
(IN THOUSANDS)
<S> <C> <C>
Proved properties.............................................................. $ 298,113 $ 318,179
Unproved properties............................................................ 8,335 7,089
---------- -----------
Total capitalized costs........................................................ 306,448 325,268
Accumulated depreciation, depletion and amortization........................... (212,680) (246,034)
---------- -----------
Net capitalized costs...................................................... $ 93,768 $ 79,234
---------- -----------
---------- -----------
</TABLE>
13. OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The estimates of proved oil and gas reserves utilized in the preparation of
the consolidated financial statements were prepared by independent petroleum
engineers. Such estimates are in accordance with guidelines established by the
Securities and Exchange Commission and the Financial Accounting Standards Board,
which require that reserve reports be prepared under economic and operating
conditions existing at the registrant's year end with no provision for price and
cost escalations except by contractual arrangements. The Company's reserves are
substantially located onshore in the United States.
The Company emphasizes that reserve estimates are inherently imprecise.
Accordingly, the estimates are expected to change as more current information
becomes available. In addition, a portion of the Company's proved reserves is
undeveloped, which increases the imprecision inherent in estimating reserves
which may ultimately be produced.
F-16
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
13. OIL AND GAS RESERVE INFORMATION (UNAUDITED) (CONTINUED)
The following table sets forth proved oil and gas reserves together with the
changes therein (oil in MBbls, gas in MMcf, gas converted to BOE at one Bbl per
six Mcf):
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------------------------------------------
1993 1994 1995
------------------------------- ------------------------------- ---------
OIL GAS BOE OIL GAS BOE OIL
--------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Proved reserves
Beginning of period............................. 7,867 58,350 17,592 5,671 59,418 15,574 5,304
Revisions....................................... (1,913) 886 (1,765) (403) (11,565) (2,329) 98
Extensions and discoveries...................... 1,598 10,546 3,355 1,321 676 1,433 2,392
Purchases of minerals-in-place.................. -- -- -- 424 6,531 1,512 --
Production...................................... (1,881) (10,364) (3,608) (1,709) (8,369) (3,104) (1,831)
--------- --------- --------- --------- --------- --------- ---------
End of period................................... 5,671 59,418 15,574 5,304 46,691 13,086 5,963
--------- --------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- --------- ---------
Proved developed reserves
Beginning of period............................. 5,601 42,893 12,750 4,702 43,366 11,930 4,635
--------- --------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- --------- ---------
End of period................................... 4,702 43,366 11,930 4,635 38,505 11,052 5,381
--------- --------- --------- --------- --------- --------- ---------
--------- --------- --------- --------- --------- --------- ---------
<CAPTION>
GAS BOE
--------- ---------
<S> <C> <C>
Proved reserves
Beginning of period............................. 46,691 13,086
Revisions....................................... (914) (54)
Extensions and discoveries...................... 564 2,486
Purchases of minerals-in-place.................. -- --
Production...................................... (6,845) (2,972)
--------- ---------
End of period................................... 39,496 12,546
--------- ---------
--------- ---------
Proved developed reserves
Beginning of period............................. 38,505 11,052
--------- ---------
--------- ---------
End of period................................... 31,668 10,659
--------- ---------
--------- ---------
</TABLE>
The standardized measure of discounted future net cash flows relating to
proved reserves was as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1993 1994 1995
---------- ---------- ----------
<S> <C> <C> <C>
(IN THOUSANDS)
Future cash inflows...................................... $ 203,445 $ 165,043 $ 191,191
Future costs:
Production............................................. (55,774) (52,020) (55,626)
Development............................................ (14,741) (8,280) (9,295)
Income taxes........................................... (14,088) -- (9,875)
---------- ---------- ----------
Future net cash flows.................................... 118,842 104,743 116,395
10% discount factor...................................... (28,945) (30,533) (27,565)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows.................................................. $ 89,897 $ 74,210 $ 88,830
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
F-17
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
13. OIL AND GAS RESERVE INFORMATION (UNAUDITED) (CONTINUED)
Changes in the standardized measure of discounted future net cash flows
relating to proved reserves were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1994 1995
---------- ---------- ----------
<S> <C> <C> <C>
(IN THOUSANDS)
Standardized measure, beginning of period................. $ 94,949 $ 89,897 $ 74,210
Net changes in sales prices, net of production costs...... (19,722) (9,926) 12,515
Revisions of quantity estimates........................... (11,367) (12,917) (383)
Accretion of discount..................................... 12,505 9,072 7,421
Changes in future development costs, including development
costs incurred that reduced future development costs.... 4,075 10,415 3,777
Changes in timing and other............................... 5,407 (2,196) (3,460)
Net change in income taxes................................ 29,852 819 --
Extensions and discoveries................................ 16,451 9,479 25,100
Sales, net of production costs............................ (42,253) (30,842) (30,350)
Purchases of minerals-in-place............................ -- 10,409 --
---------- ---------- ----------
Standardized measure, end of period....................... $ 89,897 $ 74,210 $ 88,830
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
F-18
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
<S> <C> <C>
(UNAUDITED)
CURRENT ASSETS
Cash and cash equivalents......................................................... $ 1,303 $ 1,241
Accounts receivable:
Trade, net...................................................................... 1,184 845
Affiliates...................................................................... 738 155
Oil and gas sales............................................................... 6,615 7,603
Inventory......................................................................... 505 418
Other............................................................................. 565 635
------------ -------------
10,910 10,897
------------ -------------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method................................. 325,268 345,904
Natural gas gathering and processing systems...................................... 6,951 7,637
Other............................................................................. 9,460 9,526
------------ -------------
341,679 363,067
Less accumulated depreciation, depletion and amortization......................... (259,533) (278,377)
------------ -------------
Property and equipment, net..................................................... 82,146 84,690
------------ -------------
OTHER ASSETS........................................................................ 105 60
------------ -------------
$ 93,161 $ 95,647
------------ -------------
------------ -------------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade........................................................................... $ 6,911 $ 8,219
Affiliates...................................................................... 346 647
Oil and gas sales............................................................... 4,813 6,311
Current maturities of long-term debt.............................................. 11,509 118
Accrued liabilities and other..................................................... 1,048 1,161
------------ -------------
24,627 16,456
------------ -------------
LONG-TERM DEBT...................................................................... 33,538 36,522
------------ -------------
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 and
outstanding--7,409,664 shares in 1995 and 7,490,321 shares in 1996.............. 741 749
Additional paid-in capital........................................................ 52,912 53,264
Retained deficit.................................................................. (18,657) (11,344)
------------ -------------
34,996 42,669
------------ -------------
$ 93,161 $ 95,647
------------ -------------
------------ -------------
</TABLE>
F-19
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- --------------------
1995 1996 1995 1996
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales................................................... $ 9,911 $ 14,619 $ 33,133 $ 42,136
Natural gas services................................................ 777 965 4,494 2,914
--------- --------- --------- ---------
Total revenues.................................................... 10,688 15,584 37,627 45,050
--------- --------- --------- ---------
COSTS AND EXPENSES
Lease operations.................................................... 3,245 3,647 10,231 10,808
Exploration......................................................... 431 236 863 515
Natural gas services................................................ 588 792 3,038 2,363
Depreciation, depletion and amortization............................ 6,201 5,891 20,011 17,743
Impairment of property and equipment................................ -- -- -- 1,186
General and administrative.......................................... 722 728 2,739 2,399
--------- --------- --------- ---------
Total costs and expenses.......................................... 11,187 11,294 36,882 35,014
--------- --------- --------- ---------
Operating income (loss)........................................... (499) 4,290 745 10,036
Interest expense.................................................... 1,233 840 4,224 2,783
Other income (expense).............................................. 5,949 20 6,198 60
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES............................................ 4,217 3,470 2,719 7,313
INCOME TAX EXPENSE.................................................... -- -- -- --
--------- --------- --------- ---------
NET INCOME............................................................ $ 4,217 $ 3,470 $ 2,719 $ 7,313
--------- --------- --------- ---------
--------- --------- --------- ---------
Net income per common share........................................... $ .72 $ .45 $ .47 $ .96
--------- --------- --------- ---------
--------- --------- --------- ---------
Weighted average common shares outstanding............................ 5,842 7,668 5,750 7,588
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-20
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
1995 1996
--------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................................................. $ 2,719 $ 7,313
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion and amortization................................................. 20,011 17,743
Impairment of property and equipment..................................................... -- 1,186
Exploration costs........................................................................ 807 406
(Gain) loss on sale of property and equipment, net....................................... (5,967) (21)
Other.................................................................................... 235 335
Changes in operating working capital:
Accounts receivable...................................................................... 2,068 (66)
Accounts payable......................................................................... 113 3,006
Other.................................................................................... (298) 145
--------- ---------
Net cash provided by operating activities.............................................. 19,688 30,047
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment........................................................ (15,325) (25,252)
Proceeds from sale of property and equipment............................................... 7,925 3,525
--------- ---------
Net cash used in investing activities.................................................. (7,400) (21,727)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of long-term debt............................................................... (16,281) (8,407)
Proceeds from issuance of common stock..................................................... 3,810 25
--------- ---------
Net cash used in financing activities.................................................. (12,471) (8,382)
--------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS......................................... (183) (62)
CASH AND CASH EQUIVALENTS
Beginning of period........................................................................ 1,431 1,303
--------- ---------
End of period.............................................................................. $ 1,248 $ 1,241
--------- ---------
--------- ---------
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts capitalized......................................... $ 4,318 $ 2,675
--------- ---------
--------- ---------
</TABLE>
The accompanying notes are an integral part of
these consolidated financial statements.
F-21
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1996
(UNAUDITED)
1. ORGANIZATION AND PRESENTATION
Clayton Williams Energy, Inc. (the "Company"), a Delaware corporation, was
incorporated in September 1991 for the purpose of consolidating and continuing
certain operations previously conducted by affiliates of Clayton W. Williams,
Jr. ("Mr. Williams"). Concurrent with the completion of the initial public
offering of the Company's common stock on May 26, 1993, these operations were
consolidated, and the Company succeeded to most of the oil and gas properties,
exploration and development operations and the natural gas gathering and
marketing operations of Mr. Williams and his affiliates. The consolidated
financial statements include the accounts of the Company and its subsidiaries.
All significant intercompany transactions and balances associated with the
consolidated operations have been eliminated.
The Company is primarily engaged in the exploration for and development and
production of oil and natural gas in South and East Texas, southeastern New
Mexico and the Texas Gulf Coast.
In the opinion of management, the Company's unaudited consolidated financial
statements as of September 30, 1996 and for the interim periods ended September
30, 1996 and 1995 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, 1996.
The preparation of 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.
2. LONG-TERM DEBT
Long-term debt consists of the following:
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1995 1996
------------ -------------
<S> <C> <C>
(IN THOUSANDS)
Secured Bank Credit Facility (matures July 31, 1999):
Revolving loan................................................ $ 17,000 $ 36,500
Term loan..................................................... 27,825 --
Subordinated Debt Facility...................................... -- --
Other........................................................... 222 140
------------ -------------
45,047 36,640
Less current maturities......................................... 11,509 118
------------ -------------
$ 33,538 $ 36,522
------------ -------------
------------ -------------
</TABLE>
SECURED BANK CREDIT FACILITY
Effective July 18, 1996, the Company and its banks amended and restated the
secured bank credit facility to combine the term loan and revolving loan
facilities into one reducing revolver facility, the limit of which is determined
by a borrowing base established by the banks. The borrowing base is subject to a
F-22
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1996
(UNAUDITED)
2. LONG-TERM DEBT (CONTINUED)
monthly commitment reduction of $1 million beginning July 31, 1996. At September
30, 1996, the adjusted borrowing base was $49 million, and the outstanding
indebtedness under the secured bank credit facility was $36.5 million, resulting
in an availability at that date of $12.5 million. The borrowing base and the
monthly commitment reduction are scheduled to be redetermined in November 1996
and at least semi-annually thereafter; however, the Company or the banks may
request such redeterminations at any other time during the year. Any
redetermination will be made at the discretion of the banks. If, at any time,
outstanding advances plus letters of credit exceed the borrowing base, 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 the facility to a term obligation based on
amortization formulas set forth in the loan agreement. The loan agreement
requires the Company to pledge its oil and gas properties to secure advances
under the secured bank credit facility.
Based on the terms of the amended loan agreement, no portion of the
outstanding balances at September 30, 1996 is deemed to be a current liability
since the outstanding balances are less than the stated borrowing base, as
adjusted for the monthly commitment reductions scheduled to occur within the
next year. Therefore, current maturities of long-term bank debt, as set forth in
the accompanying consolidated balance sheet, reflect a reduction of $11.4
million from the comparable balances at December 31, 1995.
All outstanding balances on the secured bank credit facility may be
designated, at the Company's option, as either "Base Rate Loans" or "Eurodollar
Loans" (as defined in the agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans will bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 1/2% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans will bear interest at the LIBOR rate for a fixed period of time
elected by the Company plus a Eurodollar Margin ranging from 1.25% to 2% per
annum. At September 30, 1996, the Company's indebtedness under these facilities
consisted of $500,000 of Base Rate Loans at a rate of 8.6% and $36 million of
Eurodollar Loans at a rate of 7.2%.
In addition, the Company pays the banks a commitment fee equal to 1/2% per
annum on the unused portion of the revolving loan commitment. Interest and fees
are payable quarterly, and all outstanding principal and interest will be due
July 31, 1999.
SUBORDINATED DEBT FACILITY
In June 1995, the Company obtained a commitment from the Agent bank in its
secured bank credit facility to loan the Company up to $5.5 million under a
subordinated debt facility which provides for interest at a minimum rate of
14.25% per year, plus certain commitment fees, with interest payable monthly and
principal payable at maturity on July 31, 1998. The commitment originally
expired on December 31, 1995, but was extended to December 31, 1996. The entire
amount of the facility may be prepaid without penalty or premium at any time
prior to maturity, but only if the Company obtains the approval of the lenders
in the secured bank credit facility. The Company does not plan to utilize this
subordinated debt facility prior to its expiration.
F-23
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1996
(UNAUDITED)
3. FORWARD SALE TRANSACTIONS
The Company accounts for forward sale and put option arrangements as hedging
activities and, accordingly, gains and losses are included in oil and gas
revenues in the period the hedged production is sold. Included in oil and gas
revenues during the nine months ended September 30, 1996 are net losses from
these activities totaling $1,154,000 (comprised of losses of $1,297,000,
partially offset by gains of $143,000). None of the Company's future oil or gas
production is subject to hedging arrangements at the present time.
4. STOCK COMPENSATION PLANS
In March 1996, the Company granted non-qualified options to purchase 121,500
shares of common stock to certain of its employees under the 1993 Stock
Compensation Plan ("1993 Plan"). The options, which have an exercise price of
$3.25 per share (market value at date of grant), are exercisable at a rate of
25% per year and expire seven years from the date of grant. In June 1996, the
Company amended the 1993 Plan to increase the number of shares reserved for
issuance thereunder from 298,200 shares to 898,200 shares.
In May 1995, the Company's Board of Directors adopted two stock compensation
plans, one for selected officers and one for outside directors of the Company.
These plans permit the Company to pay all or part of selected executives'
salaries and all outside director's fees in Common Stock in lieu of cash. During
the nine months ended September 30, 1996, the Company issued Mr. Williams 60,245
shares of Common Stock in lieu of cash compensation aggregating $289,716, and
issued 10,002 shares to three outside directors in lieu of cash compensation
aggregating $45,000. Subsequent to September 30, 1996, the Company issued Mr.
Williams an additional 5,598 shares and issued an aggregate of 1,579 shares to
three outside directors in lieu of cash compensation aggregating $78,641.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123 ("SFAS 123"), "Accounting for
Stock-Based Compensation." SFAS 123 establishes a fair value method and
disclosure standards for stock-based employee compensation arrangements, such as
stock compensation and stock option plans. As allowed by SFAS 123, the Company
will continue to follow the provisions of Accounting Principles Board Opinion
No. 25 for such stock-based compensation arrangements, and will disclose the pro
forma effects of applying SFAS 123 for 1995 and 1996 in its 1996 annual
financial statements. Such pro forma effects on results of operations for 1995
and the nine month period ended September 30, 1996 are not expected to be
significant.
5. NET INCOME (LOSS) PER COMMON SHARE
Net income (loss) per common share is based on the weighted average number
of common and common equivalent shares, if dilutive, outstanding during each
period. Common stock equivalents were not included in the computation of net
income per share in the 1995 periods since the effect was anti-dilutive.
6. SALE OF ASSETS
In January 1996, the Company sold its rights to the Buda and Georgetown
formations under approximately 28,000 net acres in Robertson County, Texas for
$3.5 million. Certain leases covered by the
F-24
<PAGE>
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1996
(UNAUDITED)
6. SALE OF ASSETS (CONTINUED)
sale must be extended during 1996 and the Company estimates that it will be
required to spend, in the aggregate, approximately $550,000 in this effort. The
Company also granted the purchaser the option to acquire additional Buda and
Georgetown rights under approximately 36,000 net acres in Burleson County,
Texas, which option was subsequently released by the purchaser. The net proceeds
were used to repay indebtedness on the secured bank credit facility, resulting
in an increase in funds then available for borrowing of $2.9 million. No gain or
loss was recognized on the sale.
7. IMPAIRMENT OF PROPERTY AND EQUIPMENT
During the quarter ended June 30, 1996, the Company revised its estimates of
proved oil and gas reserves attributable to one undeveloped location in the
Texas Gulf Coast area. As a result, the Company recorded a provision for
impairment of property and equipment of $1.2 million in accordance with
Statement of Financial Accounting Standards No. 121, "Accounting for Impairment
of Long-Lived Assets."
8. INCOME TAXES
Although the Company recorded net income of $7.3 million for financial
reporting purposes during the nine months ended September 30, 1996, no provision
for income tax expense is required since the Company has net operating loss
carryforwards of approximately $32 million available to offset any taxable
income generated by the Company during 1996. A valuation allowance against these
net operating loss carryforwards was recorded at December 31, 1995.
9. CHANGES IN AUTHORIZED CAPITAL
In October 1996, the Company amended its Certificate of Incorporation to
increase the number of authorized shares of common stock from 10,000,000 shares
to 15,000,000 shares and to authorize the issuance of 3,000,000 shares of
preferred stock, $.10 par value per share, on terms and preferences to be
determined by the Board of Directors.
F-25
<PAGE>
ANNEX A
September 30, 1996
Clayton Williams Energy, Inc.
Six Desta Drive, Suite 3000
Midland, Texas 79705
Attention Mr. Greg Benton
Gentlemen:
Subject: Summary Letter (for Inclusion in a Prospectus included in a
Registration Statement for Clayton Williams Energy, Inc. on Form S-2)
of the Evaluation of Oil and Gas Reserves
1) to the Interests of Clayton Williams Energy, Inc. in Domestic Oil and
Gas Properties and
2) to the Interests of Warrior Gas Company [a Subsidiary of Clayton
Williams Energy, Inc.] in the Gataga Gas Unit No. 5A, Vermejo
(Ellenburger) Field, Loving County, Texas, Effective July 1, 1996, for
Disclosure to the Securities and Exchange Commission, Utilizing Aries
Software, Williamson Project 6.8430
In accordance with your request, Williamson Petroleum Consultants, Inc.
(Williamson) has prepared this summary letter for inclusion in a Prospectus for
Clayton Williams Energy, Inc. (Williams Energy) of the Williamson report
entitled "Evaluation of Oil and Gas Reserves 1) to the Interests of Clayton
Williams Energy, Inc. in Domestic Oil and Gas Properties and 2) to the Interests
of Warrior Gas Company in the Gataga Gas Unit No. 5A, Vermejo (Ellenburger)
Field, Loving County, Texas, Effective July 1, 1996, for Disclosure to the
Securities and Exchange Commission, Utilizing Aries Software, Williamson Project
6.8430" (the Williamson report). All values and discussion of proved reserves
and net revenues, data utilized, assumptions, and qualifications are taken from
and include by reference data from the Williamson report.
I. ESTIMATED RESERVES AND ESTIMATED FUTURE NET REVENUES
Projections of the reserves that are attributable to the evaluated interests
of Williams Energy and Warrior Gas Company (Warrior) were based on economic
parameters and operating conditions considered applicable as of July 1, 1996 and
may be used in disclosure to the Securities and Exchange Commission (SEC).
The present values of the estimated future net revenues from proved reserves
were calculated using a discount rate of 10.00 percent per year and were
computed in accordance with the financial reporting requirements of the SEC.
Following is a summary of the results of the evaluation of proved reserves
effective July 1, 1996:
<TABLE>
<CAPTION>
PROVED PROVED
DEVELOPED DEVELOPED PROVED
PRODUCING NON- PRODUCING UNDEVELOPED
(PDP) (PDNP) (PU) TOTAL PROVED
------------- ------------- ------------ -------------
<S> <C> <C> <C> <C>
Net Reserves to the Evaluated Interests:
Oil/Condensate, MBBL.................................. 5,381,862 640.814 821.795 6,844.471
Gas, MMCF............................................. 31,030.181 409.675 6,257.249 37,697.105
Future Net Revenue, M$:
Undiscounted.......................................... 117,472.928 9,745.637 13,918.525 141,137.090
Discounted Per Annum at 10.00 Percent................. 86,124.005 6,897.704 7,319.181 100,340.891
</TABLE>
- ------------------------
Note: Due to the method of rounding within Aries Software, Total Proved may
not equal PDP + PDNP + PU.
A-1
<PAGE>
Clayton Williams Energy, Inc.
Mr. Greg Benton
September 30, 1996
Page 2
At the request of Williams Energy, Williamson used the Landmark Munro
Garrett graphics and reserves and economics evaluation software, Aries, to
prepare this evaluation. In evaluations of these properties prior to December
31, 1995, Williamson utilized its proprietary software programs. No comparative
tests have been performed to determine the difference in evaluation results of
either reserves or revenue quantities that may occur solely as a result of the
differences in the programs nor has Williamson performed tests to determine the
accuracy of Aries. However, in accordance with the request made by Williams
Energy and the general acceptance of Aries by the oil and gas industry,
Williamson has used Aries to prepare the Williamson report.
II. DEFINITIONS OF SEC RESERVES(1)
The estimated reserves presented in this summary letter are net proved
reserves, including proved developed producing, proved developed nonproducing,
and proved undeveloped reserves, and were computed in accordance with the
financial reporting requirements of the SEC. In preparing these evaluations, no
attempt has been made to quantify the element of uncertainty associated with any
category. Reserves were assigned to each category as warranted. The definitions
of oil and gas reserves pursuant to the requirements of the Securities Exchange
Act are:
PROVED RESERVES(2)
Proved reserves are the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under the economic criteria employed and existing operating conditions, i.e.,
prices and costs as of the date the estimate is made. Prices and costs include
consideration of changes provided only by contractual arrangements but not on
escalations based upon an estimate of future conditions.
A. Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes:
1. that portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and
2. the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
B. Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in
the "proved" classification when successful testing by a pilot project,
or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was
based.
C. Estimates of proved reserves do not include the following:
- ------------------------
(1) For evaluations prepared for disclosure to the Securities and Exchange
Commission, see SEC ACCOUNTING RULES. Commerce Clearing House, Inc. October
1981, Paragraph 290, Regulation 210.4-10, p.329.
(2) Any variations to these definitions will be clearly stated in the report.
A-2
<PAGE>
Clayton Williams Energy, Inc.
Mr. Greg Benton
September 30, 1996
Page 3
1. oil that may become available from known reservoirs but is classified
separately as "indicated additional reserves";
2. crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;
3. crude oil, natural gas, and natural gas liquids, that may occur in
undrilled prospects; and
4. crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal(3), gilsonite, and other such
sources.
PROVED DEVELOPED RESERVES(4)
Proved developed reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid injection
or other improved recovery techniques for supplementing the natural forces and
mechanisms of primary recovery should be included as "proved developed reserves"
only after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery will
be achieved.
PROVED UNDEVELOPED RESERVES
Proved undeveloped reserves are reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
shall be limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.
III. DISCUSSION OF SEC RESERVES
The properties in the Williamson report are located in the states of
Louisiana, Mississippi, New Mexico, Texas, and Wyoming and the state and federal
offshore waters of Louisiana with the majority of the value represented in two
areas, the Giddings field area in Brazos, Burleson, Fayette, Lee, Robertson, and
Washington Counties, Texas and the Jalmat gas field area of Lea County, New
Mexico. These two areas comprise approximately 84.9 percent of the proved
reserves with the Giddings field area contributing 70.1 percent and the Jalmat
gas field area 14.8 percent. Production is from the Austin Chalk, Austin
Chalk-3, Austin Chalk gas, Austin Chalk 11900, Buda, Edwards, Georgetown,
Navarro A, Taylor, Wilcox,
- ------------------------
(3) According to Staff Accounting Bulletin 85, excluding certain coalbed
methane gas.
(4) Williamson Petroleum Consultants, Inc. separates proved developed reserves
into proved developed producing and proved developed nonproducing reserves.
This is to identify proved developed producing reserves as those to be
recovered from actively producing wells; proved developed nonproducing
reserves as those to be recovered from wells or intervals within wells,
which are completed but shut in waiting on equipment or pipeline
connections, or wells where a relatively minor expenditure is required for
recompletion to another zone.
A-3
<PAGE>
Clayton Williams Energy, Inc.
Mr. Greg Benton
September 30, 1996
Page 4
and Wilcox 4400 formations in the Giddings field area and the Tansil, Yates,
Seven Rivers, and Queen formations in the Jalmat gas field area.
Future development in the Giddings field is focused on water fracture
treatments of existing wells and the drilling of horizontal wells in the Austin
Chalk formation updip of current producing wells in the Giddings (Austin
Chalk-3) field in Burleson and Robertson Counties.
Proved developed nonproducing reserves from hydraulic fracture treatments
were assigned to certain vertically and horizontally drilled wells. The
hydraulic fracture treatment utilized by Williams Energy in this field is
generally referred to as a "water frac". Reserves were based on analogy to
similar wells in the area which have previously been fracture treated.
The locations to be drilled are immediate offsets to existing producing
wells and are on-trend with identified fracture systems. Proved undeveloped
reserves assigned to undrilled locations were based on analogy to two or more
offset producing wells whenever possible. Rate-time forecasts were based on
analogy to the average initial producing rates, decline profiles, and projected
ultimate recoveries of the offset wells.
Future development in the Jalmat gas field area includes 26 proved
undeveloped recompletions to behind-pipe zones, stimulation treatments, and the
drilling of additional locations.
The detailed property review included in the Williamson report provides
significant detail concerning the reserves for the properties and the
engineering assumptions utilized in the evaluation.
The individual projections of lease reserves and economics include data that
describe the production forecasts and associated evaluation parameters such as
interests, taxes, product prices, operating costs, investments, salvage values,
abandonment costs, and net profit interests.
Net income to the evaluated interests is the future net revenue after
consideration of royalty revenue payable to others, taxes, operating expenses,
investments, salvage values, abandonment costs, and net profit interests, as
applicable. The future net revenue is before federal income tax and excludes
consideration of any encumbrances against the properties if such exist.
No opinion is expressed by Williamson in the Williamson report as to a fair
market value of the evaluated properties.
The future net revenue values were based on projections of oil and gas
production. It was assumed there would be no significant delay between the date
of oil and gas production and the receipt of the associated revenue for this
production.
Unless specifically identified and documented by Williams Energy as having
curtailment problems, gas production trends have been assumed to be a function
of well productivity and not of market conditions. The effect of "take or pay"
clauses in gas contracts was not considered.
Oil reserves are expressed in thousands of United States (U.S.) barrels
(MBBL) of 42 U.S. gallons. Gas volumes are expressed in millions of cubic feet
(MMCF) at 60 degrees Fahrenheit and at the legal pressure base that prevails in
the state in which the reserves are located. No adjustment of the individual gas
volumes to a common pressure base has been made.
The Williamson report includes only those costs and revenues which are
considered by Williams Energy to be directly attributable to individual leases
and areas. There could exist other revenues, overhead costs, or other costs
associated with Williams Energy or Warrior which are not included. Such
A-4
<PAGE>
Clayton Williams Energy, Inc.
Mr. Greg Benton
September 30, 1996
Page 5
additional costs and revenues are outside the scope of the Williamson report. In
accordance with the instructions of Williams Energy, operating overhead costs
were excluded for the calculation of economics for all properties operated by
Williams Energy. However, operating overhead costs were considered in the
determination of the economic lifetime and reserves of each property. The
Williamson report is not a financial statement for Williams Energy or Warrior
and should not be used as the sole basis for any transaction concerning Williams
Energy, Warrior, or the evaluated properties.
The reserves projections in this evaluation are based on the use of the
available data and accepted industry engineering methods. Future changes in any
operational or economic parameters or production characteristics of the
evaluated properties could increase or decrease their reserves. Unforeseen
changes in market demand or allowables set by various regulatory agencies could
also cause actual production rates to vary from those projected. The dates of
first production for nonproducing properties were based on estimates by Williams
Energy or Williamson and the actual dates may vary from those estimated.
Williamson reserves the right to alter any of the reserves projections and the
associated economics included in this evaluation in any future evaluations based
on additional data that may be acquired.
All data utilized in the preparation of the Williamson report with respect
to interests, reversionary status, oil and gas prices, gas categories, gas
contract terms, operating expenses, investments, salvage values, abandonment
costs, net profit interests, well information, and current operating conditions,
as applicable, were provided by Williams Energy and the operators. Data obtained
after the effective date but prior to the completion of the Williamson report
were used and were applied consistently. The reserves category assignments
reflect the status of the wells as of the effective date. July production data
were utilized on all operated properties. Daily production data through
September 10, 1996 were utilized on all new wells and wells drilled after the
effective date but prior to September 1996. These data were used in the
determination of initial producing and decline rates. Production data provided
by Williams Energy were used where available. If production data were not
provided by Williams Energy, production data from public records were utilized.
All data have been reviewed for reasonableness and, unless obvious errors were
detected, have been accepted as correct. It should be emphasized that revisions
to the projections of reserves and economics included in the Williamson report
may be required if the provided data are revised for any reason. No inspection
of the properties was made as this was not considered within the scope of this
evaluation. No investigation was made of any environmental liabilities that
might apply to the evaluated properties, and no costs are included for any
possible related expenses.
The estimates of reserves were determined by accepted industry methods and
in accordance with the Definitions of SEC Reserves included in this summary
letter. Methods utilized include extrapolation of historical production trends,
material balance determinations, analogy to similar properties, and volumetric
calculations.
Where sufficient production history and other data were available, reserves
for producing properties were determined by extrapolation of historical
production trends or through the use of material balance determinations. Analogy
to similar properties or volumetric calculations were used for nonproducing
properties and those producing properties which lacked sufficient production
history and other data to yield a definitive estimate of reserves. Reserves
projections based on analogy are subject to change due to subsequent changes in
the analogous properties or subsequent production from the evaluated properties.
Volumetric calculations are often based upon limited log and/or core analysis
data and incomplete reservoir fluid and formation rock data. Since these limited
data must frequently be extrapolated over an assumed drainage area, subsequent
production performance trends or material balance calculations may cause the
need for significant revisions to the estimates of reserves.
A-5
<PAGE>
Clayton Williams Energy, Inc.
Mr. Greg Benton
September 30, 1996
Page 6
Area oil prices were provided by Williams Energy to be used at the effective
date with the written assurance that the use of these area prices is reasonable
on an aggregate basis and would not materially affect the income from any
major-value property. After the effective date, prices were held constant for
the life of the properties. No attempt has been made to account for oil price
fluctuations which have occurred in the market subsequent to the effective date
of the Williamson report.
Area gas prices were provided by Williams Energy to be used at the effective
date with the written assurance that the use of these area prices for wellhead
volumes is reasonable on an aggregate basis and would not materially affect the
income from any major-value property. After the effective date, prices were held
constant for the life of the properties unless Williams Energy indicated that
changes were provided for by contract. A contract price of $2.65 per thousand
cubic feet (MCF) of gas was used for properties in the Southwest Rugeley field,
Matagorda County, Texas through December 1997. This price was then reduced to
the area price of $2.28 per MCF of gas and was held constant for the life of
those properties. All gas prices were applied to projected wellhead volumes.
It should be emphasized that with the current economic uncertainties,
fluctuation in market conditions could significantly change the economics of the
properties included in the Williamson report.
Operating expenses were provided by Williams Energy and represented, when
possible, the average of all recurring expenses which are billable to the
working interest owners. Lease operating expenses for all Williams
Energy-operated Base and Acquisition properties were a combination of fixed
costs and variable-by-volume costs to reflect reductions in expenses with
declining volumes as exhibited by historical operating performance. The fixed
costs on a cost per month per well basis and the variable costs on a per barrel
of oil basis varied by area. Fixed operating costs were used on the Williams
Energy-operated New Mexico wells and on all nonoperated wells. These expenses
included, but were not limited to, all direct operating expenses and any ad
valorem taxes not deducted separately. In accordance with the instructions of
Williams Energy, operating overhead costs were excluded for the calculation of
economics for all properties operated by Williams Energy. However, operating
overhead costs were considered in the determination of the economic lifetime and
reserves of each property. These costs include any overhead costs (general and
administrative) which are billable to the working interest owners. For all
nonoperated wells, the economic lifetime and calculation of economics included
overhead costs. Expenses for workovers, well stimulations, and other maintenance
were not included in the operating expenses unless such work was expected on a
recurring basis. Judgments for the exclusion of the nonrecurring expenses were
made by Williams Energy. For new and developing properties where data were
unavailable, operating expenses were estimated by Williams Energy. Operating
costs, except for the variable expenses mentioned above, were held constant for
the life of the properties.
State production taxes have been deducted at the rates provided by Williams
Energy. County ad valorem taxes provided by Williams Energy were deducted for
those Williams Energy-operated properties located in Texas. Any ad valorem taxes
for properties in other states and nonoperated properties in Texas were
represented by Williams Energy to be included in the operating expenses.
All capital costs for drilling and completion of wells, recompletions to
behind-pipe zones, restimulation, other nonrecurring workover or operating
costs, and property abandonment costs have been deducted as applicable. These
costs were provided by Williams Energy. No adjustments were made to account for
the potential effect of inflation on these costs.
Salvage values were not provided by Williams Energy to be included in this
evaluation.
A-6
<PAGE>
Clayton Williams Energy, Inc.
Mr. Greg Benton
September 30, 1996
Page 7
IV. DECLARATION OF INDEPENDENT STATUS
Williamson is an independent consulting firm and does not own any interests
in the oil and gas properties covered by the Williamson report. No employee,
officer, or director of Williamson is an employee, officer, or director of
Williams Energy. Neither the employment of nor the compensation received by
Williamson is contingent upon the values assigned to the properties covered by
the Williamson report.
Yours very truly,
WILLIAMSON PETROLEUM CONSULTANTS, INC.
JDS/jek
A-7
<PAGE>
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NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THE OFFERING OTHER
THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE ANY
OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY, BY ANYONE IN ANY
JURISDICTION IN WHICH SUCH OFFER TO SELL OR SOLICITATION IS NOT AUTHORIZED OR IN
WHICH THE PERSON MAKING SUCH OFFER TO SELL OR SOLICITATION IS NOT QUALIFIED TO
DO SO, OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE
HEREOF.
-------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
Prospectus Summary............................. 3
Cautionary Statement Regarding Forward-Looking
Statements................................... 7
Risk Factors................................... 7
Use of Proceeds................................ 13
Price Range of Common Stock.................... 14
Dividend Policy................................ 14
Capitalization................................. 15
Selected Financial Information................. 16
Management's Discussion and Analysis of
Financial Condition and Results of
Operations................................... 17
Business and Properties........................ 25
Management..................................... 35
Principal Stockholders......................... 37
Certain Transactions and Relationships......... 38
Description of Capital Stock................... 41
Underwriting................................... 44
Legal Matters.................................. 45
Experts........................................ 45
Available Information.......................... 45
Incorporation of Certain Documents by
Reference.................................... 46
Glossary of Terms.............................. 47
Index to Consolidated Financial Statements..... F-1
Summary Reserve Report......................... A-1
</TABLE>
[LOGO]
1,250,000 SHARES
COMMON STOCK
--------------
PROSPECTUS
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RODMAN & RENSHAW, INC.
HANIFEN, IMHOFF INC.
NOVEMBER 13, 1996
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