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FORM 10-K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number 0-20838
CLAYTON WILLIAMS ENERGY, INC.
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(Exact name of registrant as specified in its charter)
DELAWARE 75-2396863
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
SIX DESTA DRIVE - SUITE 6500
MIDLAND, TEXAS 79705-5510
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(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (915) 682-6324
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock - $.10 Par Value
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(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [ ]
The aggregate market value of the outstanding Common Stock, $.10 par
value, of the registrant held by non-affiliates of the registrant as of March
24, 1999, based on the closing price as quoted on the Nasdaq Stock Market's
National Market as of the close of business on said date, was $24,606,494.
There were 8,955,082 shares of Common Stock, $.10 par value, of the
registrant outstanding as of March 24, 1999.
Documents incorporated by reference:
(1) The information required by Part III of Form 10-K is found in the
registrant's definitive Proxy Statement which will be filed with the
Commission not later than April 30, 1999. Such portions of the
registrant's definitive Proxy Statement are incorporated herein by
reference.
PART I
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements in this Form 10-K under "Item 1. Business," "Item
3. Legal Proceedings," "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations," "Item 7A. Quantitative and
Qualitative Disclosure About Market Risks," and elsewhere in this Form 10-K
constitute "forward-looking statements" within the meaning of Section 27A of
the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. All statements, other than statements of
historical facts, included in this Form 10-K that address activities, events
or developments that Clayton Williams Energy, Inc. and its subsidiaries (the
"Company") expects, projects, believes or anticipates will or may occur in
the future, including such matters as oil and gas reserves, future drilling
and operations, future production of oil and gas, future net cash flows,
future capital expenditures and other such matters, are forward-looking
statements. Such forward-looking statements involve known and unknown risks,
uncertainties, and other factors which may cause the actual results,
performance, or achievements of the Company to be materially different from
any future results, performance, or achievements expressed or implied by such
forward-looking statements. Such factors include, among others, the
following: the volatility of oil and gas prices, the Company's drilling
results, the Company's ability to replace short-lived reserves, the
availability of capital resources, the reliance upon estimates of proved
reserves, operating hazards and uninsured risks, competition, government
regulation, the ability of the Company to implement its business strategy,
and other factors referenced in this Form 10-K.
ITEM 1 - BUSINESS
SPECIAL NOTE: CERTAIN STATEMENTS SET FORTH BELOW UNDER THIS CAPTION
CONSTITUTE "FORWARD-LOOKING STATEMENTS." SEE "SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS" FOR ADDITIONAL FACTORS RELATING TO SUCH
STATEMENTS.
GENERAL
Clayton Williams Energy, Inc. and its subsidiaries (the "Company") are
primarily engaged in the exploration for and development and production of
oil and natural gas. The Company commenced operations in May 1993 following
the consolidation into the Company of substantially all of the oil and gas
and gas gathering operations previously conducted by various companies
controlled by Clayton W. Williams, Jr. and the completion of the Company's
initial public offering of Common Stock.
Prior to 1998, the Company and its predecessors concentrated their
drilling activities in the Cretaceous Trend (the "Trend"), which extends from
south Texas through east Texas, Louisiana and other southern states and
includes the Austin Chalk, Buda, and Georgetown formations. The Company
believes that it has been one of the leaders in horizontal drilling in the
Trend. From January 1, 1990 through December 31, 1998, the Company drilled or
participated in 277 gross (224.6 net) horizontal wells in the Trend.
In 1997, the Company initiated several exploratory projects designed
to reduce its dependence on Trend drilling for future production and reserve
growth. These new areas include other formations in the vicinity of its core
properties in east central Texas, as well as south Texas, Louisiana and
Mississippi.
As of December 31, 1998, the Company had estimated proved reserves
totaling 5,741 MBbls of oil and 38.9 Bcf of gas with $52.1 million of
estimated future net revenues before income taxes (discounted at 10% and
based on year-end prices). During 1998, the Company added 1,716 MBOE of
estimated proved reserves through extensions and discoveries. The Company
held interests in 633 gross (392.6 net) oil and gas wells and
1
owned leasehold interests in approximately 434,700 gross (261,647 net)
undeveloped acres at December 31, 1998.
In January 1999, the Company sold its interest in eight non-operated
oil and gas wells located in Matagorda County, Texas for $5.2 million. In
March, 1999, the Company entered into a definitive agreement for the sale of
its interests in the Jalmat Field located in Lea County, New Mexico for $12.5
million. Proceeds from these sales will be used to reduce the amount of
outstanding indebtedness on the Company's secured bank credit facility. In
the aggregate, these properties accounted for approximately 9% of the
Company's 1998 oil and gas production on a BOE basis and 22% of the Company's
estimated future net revenues (discounted at 10%) at December 31, 1998. See
"PROPERTIES" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS."
DRILLING, EXPLORATION AND PRODUCTION ACTIVITIES
Following is a discussion of the Company's significant drilling,
exploration and production activities during 1998, together with its plans
for capital and exploratory expenditures in 1999. At the present time, the
Company plans to spend only $3.8 million on exploration and development
activities during 1999, substantially all of which are projected to be spent
on the Cotton Valley Exploratory Project. The Company may increase its
planned activities for 1999 if product prices improve and if the Company is
able to obtain the capital resources necessary to finance such activities.
THE TREND
The Company has assembled a 122,000 net acre lease block (the "North
Giddings Block") in the updip area of the Giddings Field in Burleson,
Robertson and Milam Counties, Texas where the Company has drilled 110 gross
(106.2 net) horizontal oil wells through December 31, 1998.
The economic viability of the Company's Trend drilling activities is
highly dependent upon the price of oil expected to be realized during the
early years of a well's productive life due to high initial production rates
and steep decline rates which are characteristic of most Trend wells. Due to
the low oil prices that prevailed during 1998, the Company suspended its
Trend drilling activities in April 1998, thereby reducing its capital
expenditures on Trend drilling and leasing activities from $44.1 million in
1997 to $9.1 million in 1998. The Company has no plans to resume drilling and
leasing activities in the Trend during 1999. However, when oil prices improve
and stabilize, the Company plans to continue development of its Trend acreage
by conducting cyclic water stimulation treatments on many of its existing
wells and by drilling new wells in areas that warrant development on an
increased density. The suspension of Trend drilling activities for an
extended period of time may have a significant adverse effect on the
Company's oil and gas production and cash flows from operating activities in
1999 and future periods unless the Company can offset the negative impact of
such suspension through favorable drilling results from its exploration
program or through acquisitions of proved properties. See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."
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
December 31, 1998, the Company had interests in 266 gross (202.3 net)
producing wells in the Giddings Field, including 196 horizontal and 70
vertical wells. For the year ended December 31, 1998, the Company's daily net
production in the Giddings Field averaged approximately 6,353 Bbls of oil and
6,032 Mcf of gas. The Company operates 82% of its wells in the Giddings Field.
COTTON VALLEY EXPLORATORY PROJECT
During 1997, the Company completed a 3-D seismic survey covering
approximately 55,000 net acres in its North Giddings Block to explore for gas
reserves in the prolific Cotton Valley Pinnacle Reef play. As
2
opposed to Trend formations, which are encountered at depths of 5,500 to
7,000 feet in this area, the Cotton Valley formation is encountered at depths
of 15,000 to 16,000 feet. During 1998, the Company spent $10.8 million on the
Cotton Valley Exploratory Project to complete the interpretation of
approximately one-third of the seismic survey, to renew and extend leases in
this area, and to drill the J. C. Fazzino Unit #1, a 16,000-foot test well on
one of the several reef anomalies identified by the seismic survey. The
Fazzino #1 confirmed that the anomaly was in fact a pinnacle reef capable of
producing natural gas in commercial quantities. In 1999, the Company plans to
spend approximately $3.2 million to complete the well, construct a gas
pipeline and treatment facility, and renew and extend leases in the North
Giddings Block, as required.
Based upon data obtained during post-completion operations, the
Company has concluded that the Fazzino #1 penetrated the edge of the reef.
Therefore, the Company plans to drill the J. C. Fazzino Unit #2 in 1999 in an
attempt to penetrate the core of the reef. The Company is presently
negotiating with certain vendors to finance the cost of their goods and
services with respect to the Fazzino #2 on a non-recourse basis.
The Company also plans to process and evaluate the remainder of the
3-D seismic survey and to conduct a similar survey on the remainder of the
North Giddings Block. However, the timing of this activity will be
substantially dependent upon the availability of the Company's capital
resources. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES."
OTHER EXPLORATION ACTIVITIES
GLEN ROSE
The Company spent $9.2 million during 1998 to explore for gas reserves
in the Glen Rose formation utilizing the Company's horizontal drilling
expertise. The Company has assembled a 111,000 acre block of leases and
seismic options in Grimes, Walker and Madison Counties, Texas. During 1998,
the Company drilled and completed 2 gross (.5 net) horizontal gas wells on
this acreage. While the production rates on the second well are encouraging,
the Company intends to evaluate the performance of this well for several
months before assessing the commercial viability of further drilling in the
Glen Rose area. Accordingly, no amounts of capital expenditures are presently
planned for exploration activities in this area in 1999.
SOUTH TEXAS
During 1998, the Company spent $4.5 million on certain exploratory
prospects in Duval, Jim Hogg and Goliad Counties, Texas, including costs to
conduct 3-D seismic surveys, purchase other 3-D seismic data and drill 4
gross (2.8 net) exploratory wells on prospects identified by such surveys.
One of the wells was marginally productive, while three resulted in dry
holes. The Company does not intend to incur any capital expenditures on these
prospects in 1999, but may farmout to industry partners its position on
certain prospects where exploratory drilling is warranted and retain a
carried interest in any wells drilled.
LOUISIANA
The Company spent $2.3 million during 1998 on various exploratory
prospects in Louisiana. The Company completed a well on its Mamou Prospect in
Evangeline Parish, but the well is uneconomic at prevailing prices. The
Company plans to spend approximately $500,000 to drill a test well on one
prospect and plans to complete a 3-D seismic survey on another. In addition,
the Company may farmout to industry partners its position on certain
prospects where exploratory drilling is warranted and retain a carried
interest in any wells drilled.
MISSISSIPPI
During 1998, the Company spent $2.6 million on various exploratory
prospects in Mississippi, including the cost to drill 2 gross (.7 net)
exploratory wells on two of these prospects. One of the wells resulted in a
producing oil discovery, while the other was a dry hole. The Company does not
plan to incur
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any capital expenditures on these prospects in 1999, but may farmout to
industry partners its position on certain prospects where exploratory
drilling is warranted and retain a carried interest in any wells drilled.
EAST TEXAS HORIZONTAL
The Company spent $2.6 million in 1998 on an exploratory horizontal
well in the Haynesville Limestone formation in Freestone County, Texas which,
upon final evaluation, was determined to be uneconomic. The Company does not
plan any further exploration activity in this area.
ACQUISITIONS OF PROVED PROPERTIES
In October 1998, the Company purchased certain non-operated oil and
gas properties in north Texas for $1.8 million.
In November 1998, the Company and an affiliated limited partnership
acquired certain oil and gas properties in east Texas for an aggregate
purchase price of $41.2 million, net of closing adjustments. The Company
acquired an undivided 10% interest in the purchased assets for $4.9 million
of the adjusted purchase price. The Company serves as operator of
substantially all of the 108 wells acquired in the transaction. In addition,
the Company serves as general partner of the limited partnership that
acquired the remaining 90% interest. After the limited partner receives an
agreed-upon rate of return, the Company's general partnership interest will
increase from 1% to 35%.
Although no specified amounts of capital expenditures have been
designated for acquisitions of proven properties in 1999, the Company
believes that the purchase of long-lived oil and gas reserves would
effectively compliment its exploration program. Therefore, the Company plans
to actively seek and evaluate acquisition opportunities during 1999.
MARKETING ARRANGEMENTS
The Company sells substantially all of its oil production under
short-term contracts based on prices quoted on the New York Mercantile
Exchange ("NYMEX") for spot West Texas Intermediate contracts, less
agreed-upon deductions which vary by grade of crude oil. The majority of the
Company's gas production is sold under short-term contracts based on pricing
formulae which are generally market responsive.
The Company believes that the loss of any of its oil and gas
purchasers would not have a material adverse effect on its results of
operations due to the availability of other purchasers.
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. The
oil and gas industry as a whole also competes with other industries in
supplying the energy and fuel requirements of industrial, commercial and
4
individual consumers. 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 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.
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 services, 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. Order 636 and subsequent
FERC orders on rehearing have been appealed and are pending judicial review.
It is difficult to predict the ultimate impact of the orders on the Company
and its gas marketing efforts. Generally, Order 636 has eliminated or
substantially reduced the interstate pipelines' traditional role as
wholesalers of natural gas, and has 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, more restrictive pipeline imbalance tolerances and greater
associated penalties for violation of such tolerances.
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
5
by pipeline. 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 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 parties 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.
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 condition and
operations.
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TITLE TO PROPERTIES
As is customary in the oil and gas industry, the Company performs a
minimal title investigation before acquiring undeveloped properties. A title
opinion is obtained prior to the commencement of drilling operations on such
properties. The Company has obtained title opinions on substantially all of
its producing properties and believes that it has satisfactory title to such
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes
and other burdens which the Company believes do not materially interfere with
the use of or affect the value of such properties. Substantially all of the
Company's oil and gas properties are currently mortgaged to secure borrowings
under the Company's secured bank credit facility and may be mortgaged under
any future credit facilities entered into by the Company.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to the usual hazards incident to
the drilling and production of oil and gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, gas or well fluids, fires and
pollution and other environmental risks. These hazards can cause personal
injury and loss of life, severe damage to and destruction of property and
equipment, pollution or environmental damage and suspension of operation.
The Company maintains insurance of various types to cover its
operations. The limits provided under its general liability policies total
$32 million. In addition, the Company maintains operator's extra expense
coverage which provides for care, custody and control of selected wells
during drilling operations. The occurrence of a significant adverse event,
the risks of which are not fully covered by insurance, could have a material
adverse effect on the Company's financial condition and results of
operations. Moreover, no assurances can be given that the Company will be
able to maintain adequate insurance in the future at rates it considers
reasonable.
EMPLOYEES
Presently, the Company has 91 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.
OFFICES
The Company leases approximately 40,000 square feet of office space in
Midland, Texas and approximately 1,400 square feet of office space in
Houston, Texas.
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ITEM 2 - PROPERTIES
The Company's properties consist primarily of oil and gas wells and
its ownership in leasehold acreage, both developed and undeveloped. At
December 31, 1998, the Company had interests in 633 gross (392.6 net) oil and
gas wells and owned leasehold interests in 434,700 gross (261,647 net)
undeveloped acres.
RESERVES
The following table sets forth certain information as of December 31,
1998 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% ("PV-10 Value").
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL (1)
--------- ----------- ---------
Oil (MBbls)........................................................... 5,504 237 5,741
Gas (MMcf)............................................................ 32,215 6,639 38,854
MBOE.................................................................. 10,873 1,344 12,217
PV-10 Value:
Before income taxes............................................ $ 48,693 $ 3,368 $ 52,061
After income taxes............................................. $ 48,693 $ 3,368 $ 52,061
(1) Subsequent to December 31, 1998, the Company sold or contracted to sell
its interests in properties with proved reserves aggregating 284 MBbls of
oil, 14,087 MMcf of gas, and 2,632 MBOE, and with an aggregate PV-10
Value of $11.6 million.
The following table sets forth certain information as of December 31,
1998 regarding the Company's proved oil and gas reserves in each of its
principal producing areas.
PERCENTAGE OF
PROVED RESERVES PRESENT VALUE OF PRESENT VALUE OF
TOTAL OIL PERCENT OF FUTURE NET FUTURE NET
OIL GAS EQUIVALENT TOTAL OIL REVENUES BEFORE REVENUES BEFORE
AREA OR FIELD (MBBLS) (MMCF) (MBOE) EQUIVALENT INCOME TAXES INCOME TAXES
- ------------- ------- ----- --------- ---------- ---------------- ----------------
(In thousands)
Trend//.............. 4,908 7,682 6,188 50.7% $ 27,463 52.7%
Jalmat (1)........... 226 10,799 2,026 16.6 7,583 14.6
Cotton Valley........ - 7,558 1,260 10.3 5,095 9.8
East Texas........... 17 5,223 888 7.3 2,784 5.4
Texas Gulf Coast (1). 93 3,799 726 5.9 4,812 9.2
Other//.............. 497 3,793 1,129 9.2 4,324 8.3
-------- -------- --------- ---------- --------------- ---------------
Total......... 5,741 38,854 12,217 100.0% $ 52,061 100.0%
======== ======== ========= ========== =============== ================
(1) Subsequent to December 31, 1998, the Company sold approximately 83%
of its Texas Gulf Coast reserves on a BOE basis and contracted to sell
all of its Jalmat reserves.
The estimates as of December 31, 1998 of proved reserves, future net
revenues from proved reserves and the PV-10 Value before income taxes set forth
in this Form 10-K were based on a report prepared by Williamson Petroleum
Consultants, Inc. (the "Independent Engineers"). For purposes of preparing such
estimates, the Independent Engineers reviewed production data through August,
1998 for properties representing 73% 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
8
estimates as of December 31, 1998, 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. Estimated quantities of proved
reserves and future net revenues therefrom are affected by changes in oil and
gas prices. Oil and gas prices decreased substantially from December 31, 1997
to December 31, 1998, resulting in significant decreases in the Company's
estimated future net revenues and, to a lesser extent, decreases in estimated
reserve quantities. 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 December 31, 1998 were $10.33 per Bbl of oil and
$1.77 per Mcf of gas, as compared to $17.00 per Bbl and $2.33 per Mcf as of
December 31, 1997.
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
PV-10 Value, 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 Independent Engineers report relies 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. 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 herein. 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 11% of the Company's total proved reserves at December
31, 1998 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 December 31, 1998 assumes, based on the Company's estimates,
that aggregate capital expenditures by the Company of approximately $3.3
million through 2002 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.
The PV-10 Value referred to herein 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 PV-10 Value from proved reserves is 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
9
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.
The Company must 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. In particular, the Company's producing properties in
the Trend are characterized by a high initial production rate, followed by a
steep decline in production. The Company has a relatively low
reserve-to-production ratio of approximately 3.7 years (based upon the
estimated quantities of proved oil and gas reserves as of December 31, 1998,
divided by production volumes for 1998). See "ITEM 7 - MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS."
Since January 1, 1998, the Company has not filed an estimate of its
net proved oil and gas reserves with any federal authority or agency other
than the Commission.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The Company drilled, or participated in the drilling of, the following
numbers of wells during the periods indicated. Wells in progress at the end of
any period are excluded.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------
1998 1997 1996
---------------------- ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
-------- --------- --------- --------- --------- ---------
DEVELOPMENT WELLS:
Oil................. 10 6.6 33 28.0 23 20.9
Gas................. - - 1 .2 - -
Dry................. - - - - - -
-------- --------- --------- --------- --------- ---------
Total............ 10 6.6 34 28.2 23 20.9
======== ========= ========= ========= ========= =========
EXPLORATORY WELLS:
Oil................. 2 .8 8 7.5 4 4.0
Gas................. 4 2.2 - - - -
Dry................. 10 6.6 5 1.9 2 .6
-------- --------- --------- --------- --------- ---------
Total............ 16 9.6 13 9.4 6 4.6
======== ========= ========= ========= ========= =========
TOTAL WELLS:
Oil................. 12 7.4 41 35.5 27 24.9
Gas................. 4 2.2 1 .2 - -
Dry................. 10 6.6 5 1.9 2 .6
-------- --------- --------- --------- --------- ---------
Total............ 26 16.2 47 37.6 29 25.5
======== ========= ========= ========= ========= =========
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.
10
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the
Company's ownership as of December 31, 1998, of productive wells in the areas
indicated.
OIL GAS TOTAL
---------------------- ---------------------- ----------------------
GROSS NET GROSS NET GROSS NET
-------- --------- --------- --------- --------- ---------
Trend ................. 289 223.2 22 15.2 311 238.4
Jalmat ................. 37 30.0 95 76.7 132 106.7
East Texas.............. - - 108 10.7 108 10.7
Texas Gulf Coast........ 1 .4 27 11.3 28 11.7
Other................... 34 20.3 20 4.8 54 25.1
-------- --------- --------- --------- --------- ---------
Total............ 361 273.9 272 118.7 633 392.6
======== ========= ========= ========= ========= =========
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 December 31,
1998, the Company was the operator of 518 wells, or approximately 82% of the 633
total wells in which it has a working interest. Production from these operated
wells represented approximately 87% of the Company's total net production for
1998.
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.
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1998 1997 1996
------------- ------------- -------------
OIL AND GAS PRODUCTION DATA (1):
Oil (MBbls)............................. 2,528 2,903 2,203
Gas (MMcf).............................. 4,833 5,091 5,584
Total (MBOE)............................ 3,334 3,752 3,134
AVERAGE OIL AND GAS SALES PRICE (2):
Oil ($/Bbl)............................. $ 16.20 $ 19.80 $ 20.85
Gas ($/Mcf)(3).......................... $ 2.35 $ 2.64 $ 2.65
AVERAGE PRODUCTION COSTS
Lease operations ($/BOE)(4)............. $ 4.27 $ 4.32 $ 4.71
(1) Subsequent to December 31, 1998, the Company sold or contracted to sell
its interests in properties which produced an aggregate of 44 MBbls of
oil, 1,525 MMcf of gas, and 298 MBOE in 1998.
(2) Includes effects of hedging transactions.
(3) Includes natural gas liquids.
(4) 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.
11
DEVELOPMENT, EXPLORATION AND ACQUISITION 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.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1998 1997 1996
------------------ ------------------ ------------------
(IN THOUSANDS)
Property Acquisitions:
Proved.................................. $ 7,077 $ - $ 1,375
Unproved................................ 10,602 14,042 5,002
Developmental Costs....................... 7,285 32,656 20,931
Exploratory Costs......................... 22,319 13,813 6,306
------------------ ------------------ ------------------
Total................................... $ 47,283 $ 60,511 $ 33,614
================== ================== ==================
ACREAGE
The following table sets forth certain information regarding the
Company's developed and undeveloped leasehold acreage as of December 31, 1998 in
the areas indicated. This table excludes options to acquire leases and acreage
in which the Company's interest is limited to royalty, overriding royalty and
similar interests.
DEVELOPED UNDEVELOPED TOTAL
---------------------- ----------------------- ----------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
Trend........................ 116,681 105,772 106,112 83,748 222,793 189,520
Glen Rose (1)................ 8,414 2,042 112,033 71,600 120,447 73,642
Jalmat (2)................... 9,481 8,023 - - 9,481 8,023
Texas Gulf Coast (2)......... 9,156 4,220 562 163 9,718 4,383
Other (3).................... 20,768 6,041 215,993 106,136 236,761 112,177
--------- --------- --------- --------- --------- ---------
Total................. 164,500 126,098 434,700 261,647 599,200 387,745
========= ========= ========= ========= ========= =========
(1) In addition, the Company held options to acquire approximately 37,000 net
acres in this area as of December 31, 1998.
(2) Subsequent to December 31, 1998, the Company entered into a definitive
agreement for the sale of its interests in the Jalmat Field (8,023 net
acres) and also sold its interest in eight non-operated oil and gas wells
located in Matagorda County, Texas (1,736 net acres).
(3) Net undeveloped acres are attributable to the following areas:
Mississippi - 23,975; Louisiana - 22,641; Colorado - 20,756; Alabama -
13,486; Wyoming - 7,717; and other - 17,561.
ITEM 3 - LEGAL PROCEEDINGS
SPECIAL NOTE: CERTAIN STATEMENTS SET FORTH BELOW UNDER THIS CAPTION
CONSTITUTE "FORWARD-LOOKING STATEMENTS." SEE "SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS" FOR ADDITIONAL FACTORS RELATING TO SUCH
STATEMENTS.
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.
12
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.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of the security holders of the
Registrant during the fourth quarter of its fiscal year ended December 31,
1998.
13
PART II
ITEM 5 - MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
The Company's Common Stock is quoted on the Nasdaq Stock Market's
National Market under the symbol "CWEI". As of December 31, 1998, there were
approximately 1,400 beneficial and record stockholders. The following table sets
forth, for the periods indicated, the high and low sales prices for the Common
Stock, as reported on the National Market:
High Low
---------- ---------
Year Ended December 31, 1998:
Fourth Quarter............................................... $ 10 1/2 $ 6 1/2
Third Quarter................................................ 11 3/4 5 5/16
Second Quarter............................................... 12 7/8 9 1/4
First Quarter................................................ 15 1/4 7 7/8
Year Ended December 31, 1997:
Fourth Quarter............................................... $ 18 7/8 $ 12 1/2
Third Quarter................................................ 17 1/4 9 7/8
Second Quarter............................................... 15 3/4 10 1/2
First Quarter................................................ 19 7/8 11 3/4
The quotations in the table above reflect inter-dealer prices without
retail markups, markdowns or commissions. On March 24, 1999, the last reported
sale price for the Common Stock on the Nasdaq Stock Market's National Market was
$5 1/2.
The Company has not paid any cash dividends on its Common Stock, and the
Board of Directors does not anticipate paying any cash dividends in the
foreseeable future. The terms of the Company's secured bank credit facility
limit the payment of cash dividends by the Company during any fiscal year to a
maximum of 50% of the Company's net income during such period, assuming
compliance with other terms thereof. Subject to the restrictions imposed by the
Company's lenders, future dividend policy will depend on a number of factors,
including future earnings, capital requirements, the financial condition and
future prospects of the Company and such other factors as the Board of Directors
may deem relevant.
14
ITEM 6 - SELECTED FINANCIAL DATA
The following table sets forth selected consolidated financial data for
the Company as of the dates and for the periods indicated. The consolidated
financial data for each of the years in the five-year period ended December 31,
1998 was derived from audited financial statements of the Company. The data set
forth 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.
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------
1998 1997 1996 1995 1994
---------- ---------- ---------- ---------- ---------
STATEMENT OF OPERATIONS DATA: (IN THOUSANDS, EXCEPT PER SHARE DATA)
Revenues:
Oil and gas sales................. $ 51,932 $ 70,929 $ 60,610 $ 43,883 $ 43,617
Natural gas services.............. 3,795 4,559 4,281 5,388 5,868
----------- ----------- ----------- ----------- -----------
Total revenues............... 55,727 75,488 64,891 49,271 49,485
----------- ----------- ----------- ----------- -----------
Costs and expenses:
Lease operations.................. 14,237 16,205 14,776 13,533 12,775
Exploration:
Abandonments and impairments. 16,128 2,692 597 1,472 6,227
Seismic and other............ 4,501 7,629 1,036 83 912
Natural gas services.............. 3,242 3,955 3,437 3,714 3,510
Depreciation, depletion and 25,248 31,665 31,273 23,758 25,110
amortization................... 25,248 31,665 31,273 23,758 25,110
Impairment of property and
equipment (1)................... - 8,493 236 1,186 10,259
General and administrative........ 4,299 4,181 3,266 3,708 5,659
----------- ----------- ----------- ----------- -----------
Total costs and expenses..... 82,565 66,171 48,056 57,879 54,331
----------- ----------- ----------- ----------- -----------
Operating income (loss)...... (26,838) 9,317 16,835 (8,608) (4,846)
----------- ----------- ----------- ----------- -----------
Other income (expense):
Interest expense.................. (2,384) (1,767) (3,440) (5,493) (4,461)
Other income (expense) (2)........ 138 217 335 6,022 759
----------- ----------- ----------- ----------- -----------
Total other income (expense). (2,246) (1,550) (3,105) 529 (3,702)
----------- ----------- ----------- ----------- -----------
Income (loss) before income taxes.... (29,084) 7,767 13,730 (8,079) (8,548)
Income tax expense.................... - - - - -
----------- ----------- ----------- ----------- -----------
Net income (loss)..................... $ (29,084) $ 7,767 $ 13,730 $ (8,079) $ (8,548)
=========== =========== =========== =========== ===========
Net income (loss) per common share:
Basic............................. $ (3.27) $ .87 $ 1.80 $ (1.31) $ (1.50)
=========== ========== =========== =========== ===========
Diluted........................... $ (3.27) $ .85 $ 1.76 $ (1.31) $ (1.50)
=========== =========== =========== =========== ===========
Weighted average common shares
outstanding:
Basic............................. 8,905 8,888 7,624 6,165 5,700
=========== =========== ============ =========== ===========
Diluted........................... 8,905 9,094 7,800 6,165 5,700
=========== =========== =========== =========== ===========
OTHER DATA:
Net cash provided by operating
activities........................... $ 33,505 $ 39,324 $ 40,306 $ 24,203 $ 23,672
EBITDAX (3)........................... $ 33,949 $ 51,147 $ 43,412 $ 28,316 $ 27,541
DECEMBER 31,
----------------------------------------
1998 1997 1996
---------- ---------- ---------
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital (deficit)........................................... $ (15,848) $ (6,369) $ (3,422)
Total assets........................................................ 120,653 134,562 103,598
Long-term debt...................................................... 39,100 35,700 18,000
Stockholders' equity................................................ 44,394 73,074 66,214
(1) The Company adopted the provisions of Statement of Financial Accounting
Standards No. 121 "Accounting for Impairment of Long-Lived Assets"
effective October 1, 1995.
(2) The 1995 period includes a $6 million non-recurring gain on sale of two
principal gas gathering and processing systems.
(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.
15
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
SPECIAL NOTE: CERTAIN STATEMENTS SET FORTH BELOW UNDER THIS CAPTION
CONSTITUTE "FORWARD-LOOKING STATEMENTS." SEE "SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS" FOR ADDITIONAL FACTORS RELATING TO SUCH
STATEMENTS.
The following discussion is intended to assist in understanding the
Company's historical consolidated financial position at December 31, 1998,
and results of operations and cash flows for each of the three years in the
period ended December 31, 1998. The Company's historical Consolidated
Financial Statements and notes thereto included elsewhere in this Form 10-K
contain detailed information that should be referred to in conjunction with
the following discussion.
OVERVIEW
Prior to 1998, the Company and its predecessors concentrated their
drilling activities in the Trend. Oil and gas production in the Trend is
generally characterized by a high initial production rate, followed by a
steep rate of decline. In order to maintain its oil and gas reserve base,
production levels and cash flow from operations, the Company has been
required to maintain or increase its level of drilling activity and achieve
comparable or improved results from such activities. In response to low oil
prices, the Company suspended its Trend drilling activities in April 1998 and
has no plans to resume drilling in that area until oil prices improve and
stabilize.
Beginning in 1997, the Company initiated several exploratory projects
designed to reduce its dependence on Trend drilling for future production and
reserve growth. These new areas include other formations in the vicinity of
its core properties in east central Texas, as well as south Texas, Louisiana
and Mississippi, and emphasize the development of long-life gas reserves.
During 1998, the Company devoted a substantial portion of its capital
expenditures to these new areas. Of the 16 gross (9.6 net) exploratory wells
drilled in 1998, the Company successfully completed 5 gross (2.6 net)
exploratory wells in areas outside the Trend, and in addition, completed 1
gross (1 net) exploratory well in January 1999. In the aggregate, these
discoveries accounted for about 85% of the Company's 1,716 MBOE of proved
reserves added during 1998.
The most significant discovery was the J. C. Fazzino Unit #1, a Cotton
Valley Pinnacle Reef gas well in Robertson County, Texas in which the Company
owns a 100% working interest. The Company's net proved reserves on this well
are estimated to be 7.6 Bcf of gas (1,260 MBOE). The Company is presently
constructing a gas pipeline and treatment facility in order to market these
gas reserves. Prior to first sales, which are planned for May 1999, the
Company will stimulate the well in an attempt to improve initial flow rates.
The Company also plans to drill an offset well to the J. C. Fazzino #1 during
1999. See "LIQUIDITY AND CAPITAL RESOURCES - CAPITAL EXPENDITURES."
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.
16
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the
Company for the periods presented:
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
-------- -------- ---------
OIL AND GAS PRODUCTION DATA (1):
Oil (MBbls)....................................................... 2,528 2,903 2,203
Gas (MMcf)........................................................ 4,833 5,091 5,584
Total (MBOE) (2).................................................. 3,334 3,752 3,134
AVERAGE OIL AND GAS SALES PRICES (3):
Oil ($/Bbl)....................................................... $16.20 $19.80 $ 20.85
Gas ($/Mcf)....................................................... $ 2.35 $ 2.64 $ 2.65
OPERATING COSTS AND EXPENSES ($/BOE PRODUCED):
Lease operations.................................................. $ 4.27 $ 4.32 $ 4.71
Oil and gas depletion............................................. $ 9.24 $ 8.10 $ 7.32
General and administrative........................................ $ 1.29 $ 1.11 $ 1.04
NET WELLS DRILLED (4):
Exploratory Wells................................................. 9.6 9.4 4.6
Developmental Wells............................................... 6.6 28.2 20.9
(1) Subsequent to December 31, 1998, the Company sold or contracted to sell
its interests in properties which produced an aggregate of 44 MBbls of
oil, 1,525 MMcf of gas, and 298 MBOE in 1998.
(2) Gas is converted to barrel of oil equivalents (BOE) at the ratio of six
Mcf of gas to one Bbl of oil.
(3) Includes effects of hedging transactions.
(4) Excludes wells being drilled or completed at the end of each period.
1998 COMPARED TO 1997
REVENUES
Oil and gas sales decreased 27% from $70.9 million in 1997 to $51.9
million in 1998 due primarily to lower oil prices. The Company's average oil
price during the current period declined 18% (after giving effect to a $3.50 per
barrel gain on hedging activities). Excluding hedging transactions, the
Company's average price per barrel of oil declined 36% from $19.76 in 1997 to
$12.70 in 1998. Although oil production for 1998 decreased 13% as compared to
1997, several factors related to the current depressed levels of oil prices had
a negative impact on production. In April 1998, the Company suspended its Trend
drilling program until oil prices improve and stabilize. The Company also
implemented an oil curtailment strategy during 1998 which resulted in a decrease
of approximately 100,000 barrels of oil production during the year. All of the
Company's gas discoveries in 1998 were either completed late in the year or are
currently waiting on pipeline connections. Accordingly, production from new
wells has not been sufficient to offset the recent decline in oil production
attributable to the suspension of Trend drilling. Furthermore, until these wells
and other exploratory projects establish and sustain commercial levels of
production, there can be no assurance that the Company will be successful in its
efforts to offset the decline in production.
COSTS AND EXPENSES
Lease operations expenses decreased 12% from $16.2 million in 1997 to
$14.2 million in 1998 due primarily to lower production taxes resulting from a
significant decline in oil prices. Oil and gas production on a BOE basis
decreased 11% during the current period, causing a 1% decrease in lease
operations expenses on a BOE basis from $4.32 per BOE in 1997 to $4.27 per BOE
in 1998.
17
Exploration costs doubled from $10.3 million in 1997 to $20.6 million
in 1998 due primarily to the charge-off of 10 gross (6.6 net) exploratory dry
holes during the 1998 period totaling $7.7 million and $8.4 million of
unproved property impairments. These 1998 charges were offset in part by a
$3.3 million reduction in seismic costs from 1997 to 1998. Because the
Company follows the successful efforts method of accounting, the Company's
results of operations may be adversely affected during any accounting period
in which seismic costs, exploratory dry hole costs, and unproved property
impairments are expensed.
Depreciation, depletion and amortization ("DD&A") expense increased 1%
from $31.3 million in 1997 to $31.7 million in 1998 due primarily to a 14%
increase in the Company's average depletion rate per BOE attributable to the
effects of lower oil and gas prices on estimated quantities of proved
reserves. This increase in the average depletion rate was substantially
offset by an 11% decline in oil and gas production on a BOE basis. Under the
successful efforts method of accounting, costs of oil and gas properties are
amortized on a unit-of-production method based on estimated proved reserves.
The average depletion rate per BOE was $9.24 in 1998 compared to $8.10 in
1997.
General and administrative ("G&A") expenses were relatively constant
from 1997 to 1998. However, beginning in December 1998, the Company
implemented certain cost reduction measures, consisting primarily of
personnel layoffs and salary reductions, in order to reduce overhead and
conserve financial resources. Through these efforts, the Company expects to
reduce G&A expenses in 1999 by approximately 33% on an annualized basis.
The Company recorded a provision for impairment of property and
equipment of $8.5 million during the fourth quarter of 1998 in accordance
with Statement of Financial Accounting Standards No. 121 "Accounting for
Impairment of Long-Lived Assets" ("SFAS 121"), as compared to a $236,000
provision in 1997. The 1998 provision applied to certain oil and gas
properties in east central Texas, south Texas, the Texas Gulf Coast,
Louisiana, and Mississippi and was caused primarily by a decline in
forecasted oil and gas prices.
INTEREST EXPENSE AND OTHER
Interest expense increased 33% from $1.8 million in 1997 to $2.4
million in 1998 due primarily to higher average levels of indebtedness on the
Company's secured bank credit facility (the "Credit Facility"), offset in
part by an increase in capitalized interest and slightly lower average
interest rates. The average daily principal balance outstanding on such
facility during 1998 was $40.8 million compared to $24 million in 1997. The
effective annual interest rate on bank debt, including bank fees, during the
1998 period was 8.1% compared to 8.7% in 1997. Capitalized interest was
$621,000 higher during the 1998 period due to a significant increase in
unproved acreage.
1997 COMPARED TO 1996
REVENUES
Oil and gas sales increased 17% from $60.6 million in 1996 to $70.9
million in 1997 due primarily to a 32% increase in oil production. The effect
of higher oil production was partially offset by a 5% decrease in oil prices
and a 9% decline in gas production. Production from wells completed
subsequent to December 31, 1996 accounted for approximately 42% of total oil
production for the 1997 period, which more than offset the effects of steep
production declines from previously existing Trend wells. The Company plans
to discontinue Trend drilling in April 1998 pending an improvement in oil
prices, which have fallen to their lowest levels in four years. The
suspension of Trend drilling activities for an extended period of time may
adversely affect the Company's production and revenues in 1998.
18
COSTS AND EXPENSES
Lease operations expenses increased 9% from $14.8 million in 1996 to
$16.2 million in 1997 while oil and gas production on a BOE basis increased
20%, resulting in a decrease in lease operations expenses on a BOE basis from
$4.71 per BOE in 1996 to $4.32 per BOE in 1997. Higher initial rates of
production on several of the wells completed during 1997 contributed
materially to the decline in lease operations expenses per BOE.
Exploration costs increased from $1.6 million in 1996 to $10.3 million
in 1997 due primarily to costs incurred during 1997 in connection with
exploration projects initiated during the fourth quarter of 1996. The Company
plans to spend approximately $17 million in 1998 on exploratory prospects.
Because the Company follows the successful efforts method of accounting, the
Company's results of operations may be adversely affected during any
accounting period in which seismic costs, exploratory dry hole costs, and
unproved property impairments are expensed.
DD&A expense increased 32% from $23.8 million in 1996 to $31.3 million
in 1997 due primarily to a 20% increase in oil and gas production on a BOE
basis, combined with an 11% increase 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 average depletion rate per BOE was $8.10 in
the 1997 period compared to $7.32 in the 1996 period.
G&A expenses increased 27% from $3.3 million in 1996 to $4.2 million
in 1997 due primarily to increased personnel costs. In response to an
increase in demand for skilled technical and managerial personnel in the oil
and gas industry and an increase in the Company's level of exploration and
development activities, the Company has hired additional personnel and
increased salaries of existing personnel.
INTEREST EXPENSE
Interest expense decreased 47% from $3.4 million in 1996 to $1.8
million in 1997 due primarily to lower average levels of indebtedness on the
Credit Facility and, to a much lesser extent, lower average interest rates.
The average daily principal balance outstanding on such facility during the
1997 period was $24 million compared to $36.9 million in 1996. The effective
annual interest rate on bank debt, including bank fees, during the 1997
period was 8.7% compared to 9.4% in 1996.
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 1999, and the expected capital resources needed to
finance such plans.
19
CAPITAL EXPENDITURES
At present time, the Company plans to spend only $3.8 million on
exploration and development activities during 1999, substantially all of
which is projected to be spent on the Cotton Valley Exploratory Project in
the North Giddings Block. In January 1999, the Company completed the J. C.
Fazzino Unit #1, a Cotton Valley Pinnacle Reef well in Robertson County,
Texas drilled into one of several reef anomalies identified by a 3-D seismic
survey conducted in 1997. The Company is currently constructing a gas
pipeline and treatment facility for the well and plans to acidize the well
prior to first production. In the aggregate, the Company expects to spend
approximately $3.2 million in 1999 to complete the well and facilities and to
renew and extend leases in the North Giddings Block, as required. In
addition, the Company plans to drill an offset well to the J. C. Fazzino Unit
#1 during 1999 utilizing a vendor financing program.
The Company may increase its planned activities for 1999 if product
prices improve and if the Company is able to obtain the capital resources
necessary to finance such activities. See "BUSINESS - DRILLING, EXPLORATION
AND PRODUCTION ACTIVITIES."
CAPITAL RESOURCES
CREDIT FACILITY
The Credit Facility provides for a revolving loan facility in an
amount not to exceed the lesser of the borrowing base, as established by the
banks, or that portion of the borrowing base determined by the Company to be
the elected borrowing limit. At December 31, 1998, the borrowing base was $57
million and the outstanding advances were $54.9 million. In January 1999, the
borrowing base was reduced to $53 million to give effect to the sale of
certain assets in Matagorda County, Texas. The borrowing base is subject to
redetermination at any time, but at least semi-annually, and is made at the
discretion of the banks.
Anticipating the adverse affects that low product prices could have on
the borrowing base, the Company initiated efforts late in 1998 to sell its
interests in two properties in order to reduce the amount of outstanding
indebtedness on the Credit Facility. In January 1999, the Company completed
the sale of its interest in eight non-operated oil and gas wells located in
Matagorda County, Texas for $5.2 million. In March 1999, the Company entered
into a definitive agreement for the sale of its interests in the Jalmat Field
located in Lea County, New Mexico for $12.5 million. The Jalmat sale is
scheduled to close in April 1999.
In March 1999, the banks completed a borrowing base review and elected
to maintain the borrowing base at $53 million until the Company consummates
the sale of its Jalmat assets. Once the Jalmat sale is completed, the
borrowing base will reduce to $43 million and will also be subject to monthly
commitment reductions of $650,000 beginning in July 1999. The adjusted
borrowing base will remain in effect until the next scheduled borrowing base
redetermination in November 1999. However, if the Jalmat sale does not occur
by May 1, 1999, the banks will cause the borrowing base to be redetermined.
If the redetermined borrowing base is less than the amount of outstanding
indebtedness, the Company will be required to (i) pledge additional
collateral, (ii) prepay the excess in not more than five equal monthly
installments, or (iii) elect to convert the entire amount of outstanding
indebtedness to a term obligation based on amortization formulas set forth in
the loan agreement.
WORKING CAPITAL AND CASH FLOW
During 1999, the Company generated cash flow from operating activities
of $33.5 million, borrowed $19.2 million on the Credit Facility, and spent
$53.7 million on capital expenditures.
The Company's working capital deficit increased from $6.4 million at
December 31, 1997 to $15.8 million at December 31, 1998. The Company
classified $15.8 million of its outstanding indebtedness on the Credit
Facility as a current liability based on the required levels of repayments
during 1999. The Company also
20
classified the net book value of properties sold or contracted for sale in
1999 as properties held for resale and, accordingly, reported $7.5 million as
a current asset at December 31, 1998.
ADDITIONAL CAPITAL RESOURCES
The Company believes that the funds which will be available from the
completed and pending sales of assets, combined with operating cash flow,
will be adequate to fund the required reductions in indebtedness on the
Credit Facility and the projected capital expenditures for 1999. However,
because future cash flows and the availability of borrowings under the Credit
Facility are subject to a number of variables, such as prevailing prices of
oil and gas, actual production from existing and newly-completed wells, the
Company's success in developing and producing new reserves, and the
uncertainty with respect to the amount of funds which may ultimately be
required to finance the Company's exploration program, there can be no
assurance that the Company's capital resources will be sufficient to sustain
the Company's exploratory and development activities.
If funds available from asset sales, combined with operating cash
flow, are not sufficient to fund its debt repayments and anticipated levels
of capital expenditures, the Company will be required to seek alternative
forms of capital resources, including the sale of other assets and the
issuance of debt or equity securities. Although the Company believes it will
be able to obtain funds pursuant to one or more of these alternatives, if
needed, management cannot be assured that any such capital resources will be
available to the Company. If additional capital resources are needed, but the
Company is unable to obtain such capital resources on a timely basis, the
Company may not be able to maintain a level of liquidity sufficient to meet
its obligations as they mature or maintain compliance with the required
financial covenants contained in the Credit Facility.
INFLATION
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 1998.
INFORMATION SYSTEMS FOR THE YEAR 2000
Historically, certain computer software systems, as well as certain
hardware containing embedded chip technology, such as microcontrollers and
microprocessors, were designed to utilize a two-digit date field and
consequently, they may not be able to properly recognize dates in the year
2000. This could result in system failures. The Company relies on its
computer-based management information systems, as well as embedded
technology, to operate instruments and equipment in conducting its day-to-day
business activities. Certain of these computer-based programs and embedded
technology may not have been designed to function properly with respect to
the application of dating systems relating to the year 2000.
In response, the Company has developed a "Year 2000 Plan" and, in
1998, established an internal group to identify and assess potential areas of
risk and to make any required modifications to its computer systems and
equipment used in oil and gas exploration, production, gathering and gas
processing activities. The Year 2000 Plan is comprised of various phases,
including assessment, remediation, testing and contingency plan development.
The Company believes this plan will provide reasonable assurance that its
business activities and facilities will continue to operate safely and
reliably, and without material interruption after 1999.
The Company has completed all phases of the Year 2000 Plan as it
relates to its internal systems and hardware. The Company's inventory of
computer hardware and software is substantially Year 2000 compliant. The
programming modifications for the oil and gas accounting and production
systems were completed by the software vendor in 1997 and were installed and
tested by the Company in November 1998.
21
The Company has monitor and control equipment with embedded chip
technology which are utilized in production and gas processing operations.
The various systems were reviewed in conjunction with the overall Year 2000
Plan and were found to be Year 2000 compliant based on manufacturers'
representations.
The Company has also undertaken to monitor the compliance efforts of
purchasers, vendors, contractors and other third parties ("Third Party
Providers") with whom it does business and whose computer-based systems
and/or embedded technology equipment interface with those of the Company to
ensure that operations will not be adversely affected by the Year 2000
compliance problems of others. There can be no assurance that there will not
be an adverse effect on the Company if Third Party Providers do not convert
their respective systems in a timely manner and in a way that is compatible
with the Company's information systems and embedded technology equipment.
However, management believes that ongoing communication with and assessment
of the compliance efforts and status of Third Party Providers will minimize
these risks. Since the Company's operations generally are not dependent on
any single Third Party Provider, the Company is prepared to select Third
Party Providers which are Year 2000 compliant by the fourth quarter of 1999.
To date, the costs to implement the Year 2000 Plan have been nominal
since the primary area for remediation involved software covered by a
maintenance agreement. The Company does not expect to incur any significant
costs during the remainder of 1999 to complete the Year 2000 Plan.
Although the Company anticipates minimal business disruptions as a
result of Year 2000 issues, in the event the computer-based programs and
embedded technology equipment of the Company, or that owned and operated by
Third Party Providers, should fail to function properly, possible
consequences include, but are not limited to, loss of communication links,
inability to produce, process and sell oil and natural gas, loss of electric
power, and inability to automatically process commercial transactions or
engage in similar automated or computerized business activities.
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
SPECIAL NOTE: CERTAIN STATEMENTS SET FORTH BELOW UNDER THIS CAPTION
CONSTITUTE "FORWARD-LOOKING STATEMENTS." SEE "SPECIAL NOTE REGARDING
FORWARD-LOOKING STATEMENTS" FOR ADDITIONAL FACTORS RELATING TO SUCH
STATEMENTS.
The Company's business is impacted by fluctuations in commodity prices
and interest rates. The following discussion is intended to identify the
nature of these market risks, describe the Company's strategy for managing
such risks, and to quantify the potential affect of market volatility on the
Company's financial condition and results of operations.
OIL AND GAS PRICES
The Company's financial condition, results of operations, and capital
resources are highly dependent upon the prevailing market prices of, and
demand for, oil and natural gas. These commodity prices are subject to wide
fluctuations and market uncertainties due to a variety of factors that are
beyond the control of the Company. These factors include the level of global
demand for petroleum products, foreign supply of oil and gas, the
establishment of and compliance with production quotas by oil-exporting
countries, weather conditions, the price and availability of alternative
fuels, and overall economic conditions, both foreign and domestic. It is
impossible to predict future oil and gas prices with any degree of certainty.
Sustained weakness in oil and gas prices may adversely affect the Company's
financial condition and results of operations, and may also reduce the amount
of net oil and gas reserves that the Company can produce economically. Any
reduction in reserves, including reductions due to price fluctuations, can
have an adverse affect on the Company's ability to obtain capital for its
exploration and development activities. Similarly,
22
any improvements in oil and gas prices can have a favorable impact on the
Company's financial condition, results of operations and capital resources.
Based on the Company's 1998 levels of oil and gas production, a $1 change in
the price per Bbl of oil and a $.10 change in the price per Mcf of gas would
result in an aggregate change in gross revenues of approximately $3 million.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure
to price fluctuations. While the use of these hedging arrangements limits the
downside risk of price declines, such use may also limit any benefits which
may be derived from price increases. The Company uses various financial
instruments, such as swaps, collars and puts, whereby monthly settlements are
based on differences between the prices specified in the instruments and the
settlement prices of certain futures contracts quoted on the NYMEX or certain
other indices. Generally, when the applicable settlement price is less than
the price specified in the contract, the Company receives a settlement from
the counterparty based on the difference. Similarly, when the applicable
settlement price is higher than the specified price, the Company pays the
counterparty based on the difference. The instruments utilized by the Company
differ from futures contracts in that there is not a contractual obligation
which requires or permits the future physical delivery of the hedged products.
During 1998 and continuing into 1999, the oil and gas industry has
operated in a depressed commodity price environment. Oil prices during the
first quarter of 1999 fell to their lowest levels in history when adjusted
for inflation. Although oil prices improved to some degree in late March
1999, current prices remain substantially lower than levels achieved in 1997.
In November 1997, the Company entered into swap arrangements on a significant
portion of its 1998 oil production and realized a gain of $8.8 million in
1998 on oil hedges. In addition, the Company hedged a portion of its 1998 gas
production at various times beginning in November 1997 and realized net gains
of $1.1 million in 1998 on gas hedges.
As of December 31, 1998, the Company had options to sell an aggregate
of 800,000 barrels of oil production from January 1999 through June 1999 at a
price of $10.00 per barrel. The Company plans to enter into additional
hedging arrangements when and if the market prices for future oil and gas
production improve to favorable levels based on management's analysis of
price expectations.
INTEREST RATES
All of the Company's outstanding indebtedness at December 31, 1998 is
subject to market rates of interest as determined from time to time by the
banks pursuant to the Credit Facility. See "CAPITAL RESOURCES". The Company
may designate borrowings under the Credit Facility as either "Base Rate
Loans" or "Eurodollar Loans." Base Rate Loans bear interest at a fluctuating
rate that is linked to the discount rates established by the Federal Reserve
Board. Eurodollar Loans bear interest at a fluctuating rate that is linked to
LIBOR. Any increases in these interest rates can have an adverse impact on
the Company's results of operations and cash flow. Although various financial
instruments are available to hedge the effects of changes in interest rates,
the Company does not consider the risk to be significant and has not entered
into any interest rate hedging transactions. Based on the Company's
outstanding indebtedness at December 31, 1998 of $54.9 million, a change in
interest rates of 25 basis points would affect annual interest payments by
approximately $137,000.
23
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
For the financial statements and supplementary data required by this
Item 8, see the Index to Consolidated Financial Statements included elsewhere
in this Form 10-K.
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
24
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Information required by this Item is incorporated herein by
reference to the Company's definitive proxy statement which will be filed
with the Commission within 120 days after December 31, 1998.
ITEM 11 - EXECUTIVE COMPENSATION
The information required by this Item is incorporated herein by
reference to the Company's definitive proxy statement which will be filed
with the Commission within 120 days after December 31, 1998.
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this Item is incorporated herein by
reference to the Company's definitive proxy statement which will be filed
with the Commission within 120 days after December 31, 1998.
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated herein by
reference to the Company's definitive proxy statement which will be filed
with the Commission within 120 days after December 31, 1998.
25
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS AND SCHEDULES
For a list of the consolidated financial statements filed as part of
this Form 10-K, see the Index to Consolidated Financial Statements on page
F-1.
No financial statement schedules are required to be filed as a part of
this Form 10-K.
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the quarter ended December
31, 1998.
EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
**3.1 Second Restated Certificate of Incorporation of the Company,
filed as an exhibit to the Form S-2 Registration Statement,
Registration No. 333-13441
**3.2 Bylaws of the Company, filed as an exhibit to the Form S-1
Registration Statement, Registration No. 33-43350
**10.1 Sixth Restated Loan Agreement dated as of July 16, 1998,
among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI
Acquisitions, Inc., Bank One, Texas, N.A., Banque Paribas
and the First National Bank of Chicago, filed as an exhibit
to the June 30, 1998 Form 10-Q
*10.2 First Amendment to Sixth Restated Loan Agreement dated as of
November 20, 1998, among Clayton Williams Energy, Inc.,
Warrior Gas Co., CWEI Acquisitions, Inc., Bank One, Texas,
N.A., Paribas, Union Bank of California, N.A., and
Compass Bank.
*10.3 Second Amendment to the Sixth Restated Loan Agreement dated
as of March 26, 1999, among Clayton Williams Energy, Inc.,
Warrior Gas Co., CWEI Acquisitions, Inc., Bank One, Texas,
N.A., Paribas and Union Bank of California, N.A.
**10.4 1993 Stock Compensation Plan, filed as an exhibit to the
Form S-8 Registration Statement, Registration No. 33-68318
**10.5 First Amendment to 1993 Stock Compensation Plan, filed as an
exhibit to the December 31, 1995 Form 10-K
**10.6 Second Amendment to the 1993 Stock Compensation Plan, filed
as an exhibit to the Form S-8 Registration Statement,
Registration No. 33-68318
**10.7 Outside Directors Stock Option Plan, filed as an exhibit to
the Form S-8 Registration Statement, Registration No.
33-68316
**10.8 First Amendment to Outside Directors Stock Option Plan,
filed as an exhibit to the December 31, 1995 Form 10-K
26
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- ----------------------
**10.9 Bonus Incentive Plan, filed as an exhibit to the Form S-8
Registration Statement, Registration No. 33-68320
**10.10 First Amendment to Bonus Incentive Plan, filed as an exhibit
to the December 31, 1997 Form 10-K
**10.11 Amended and Restated 401(k) Plan & Trust, filed as an
exhibit to the December 31, 1995 Form 10-K
**10.12 Second Amendment to Amended and Restated 401(k) Plan &
Trust, filed as an exhibit to the December 31, 1995 Form
10-K
**10.13 Third Amendment to Amended and Restated 401(k) Plan & Trust,
filed as an exhibit to the December 31, 1995 Form 10-K
**10.14 Executive Incentive Stock Compensation Plan, filed as an
exhibit to the Form S-8 Registration Statement, Registration
No. 33-92834
**10.15 First Amendment to Executive Incentive Stock Compensation
Plan, filed as an exhibit to the December 31, 1996 Form 10-K
**10.16 Consolidation Agreement dated May 13, 1993 among Clayton
Williams Energy, Inc., Warrior Gas Co. and the Williams
Entities, filed as an exhibit to the Form S-1 Registration
Statement, Registration No. 33-43350
**10.17 Agreement dated April 23, 1993 between the Company and
Robert C. Lyon, filed as an exhibit to the Form S-1
Registration Statement, Registration No. 33-43350
**10.18 Service Agreement effective October 1, 1995 among Clayton
Williams Energy, Inc. and certain Williams Entities, filed
as an exhibit to the December 31, 1995 Form 10-K
**21 Subsidiaries of the Registrant, filed as an exhibit to the
December 31, 1996 Form 10-K
*23.1 Consent of Arthur Andersen LLP
*23.2 Consent of Williamson Petroleum Consultants, Inc.
*24.1 Power of Attorney
*24.2 Certified copy of resolution of Board of Directors of
Clayton Williams Energy, Inc. authorizing signature pursuant
to Power of Attorney
*27 Financial Data Schedules for the year ended December 31,
1998
- ---------------
* Filed herewith
** Incorporated by reference to the filing indicated
27
SIGNATURES
In accordance with the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CLAYTON WILLIAMS ENERGY, INC.
(Registrant)
By: /s/ CLAYTON W. WILLIAMS, JR. *
---------------------------------------
Clayton W. Williams, Jr.
Chairman of the Board, President
and Chief Executive Officer
In accordance with the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on behalf of
the registrant and in the capacities and on the dates indicated.
Signature Title Date
----------------------------------- ----------------------------------- --------------
/s/ CLAYTON W. WILLIAMS, JR. * Chairman of the Board, March 30, 1999
----------------------------------- President and Chief Executive
Clayton W. Williams, Jr. Officer and Director
/s/ L. PAUL LATHAM Executive Vice President, March 30, 1999
----------------------------------- Chief Operating Officer and
L. Paul Latham Director
/s/ MEL G. RIGGS * Senior Vice President - March 30, 1999
----------------------------------- Finance, Secretary, Treasurer,
Mel G. Riggs Chief Financial Officer and Director
/s/ STANLEY S. BEARD * Director March 30, 1999
-----------------------------------
Stanley S. Beard
/s/ WILLIAM P. CLEMENTS * Director March 30, 1999
-----------------------------------
William P. Clements
/s/ ROBERT L. PARKER * Director March 30, 1999
-----------------------------------
Robert L. Parker
*By: /s/ L. PAUL LATHAM
--------------------------------
L. Paul Latham
ATTORNEY-IN-FACT
28
CLAYTON WILLIAMS ENERGY, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Report of Independent Public Accountants............................. F-2
Consolidated Balance Sheets.......................................... F-3
Consolidated Statements of Operations................................ F-4
Consolidated Statements of Stockholders' Equity...................... F-5
Consolidated Statements of Cash Flows................................ F-6
Notes to Consolidated Financial Statements........................... F-7
F-1
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, 1998 and 1997, and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended December 31, 1998. 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, 1998 and 1997, and the results of its operations
and cash flows for each of the three years in the period ended December 31,
1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Dallas, Texas
March 11, 1999
F-2
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
DECEMBER 31,
-----------------------------------
1998 1997
--------------- ----------------
CURRENT ASSETS
Cash and cash equivalents............................................. $ 1,424 $ 2,150
Accounts receivable:
Trade, net........................................................ 6,782 4,197
Affiliates........................................................ 244 173
Oil and gas sales................................................. 3,628 9,126
Inventory............................................................. 1,230 2,530
Property held for resale.............................................. 7,521 -
Other................................................................. 482 1,243
--------------- ----------------
21,311 19,419
--------------- ----------------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method..................... 424,360 412,352
Natural gas gathering and processing systems.......................... 8,292 7,869
Other................................................................. 10,480 10,411
--------------- ----------------
443,132 430,632
Less accumulated depreciation, depletion and amortization............. (343,857) (315,559)
--------------- ----------------
Property and equipment, net....................................... 99,275 115,073
--------------- ----------------
OTHER ASSETS............................................................... 67 70
--------------- ----------------
$ 120,653 $ 134,562
=============== ================
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade............................................................. $ 16,384 $ 16,480
Affiliates........................................................ 65 603
Oil and gas sales................................................. 3,433 7,679
Current maturities of long-term debt.................................. 15,800 42
Accrued liabilities and other......................................... 1,477 984
--------------- ----------------
37,159 25,788
--------------- ----------------
LONG-TERM DEBT............................................................. 39,100 35,700
--------------- ----------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, par value $.10 per share; authorized - 3,000,000
shares; issued and outstanding - none................................ - -
Common stock, par value $.10 per share; authorized - 15,000,000
shares; issued - 8,937,561 shares in 1998 and
8,980,539 shares in 1997............................................. 894 898
Additional paid-in capital............................................ 69,744 70,856
Retained earnings (deficit)........................................... (26,244) 2,840
--------------- ----------------
44,394 74,594
Less treasury stock, at cost (95,000 shares in 1997).................. - (1,520)
--------------- ----------------
44,394 73,074
--------------- ----------------
$ 120,653 $ 134,562
=============== ================
The accompanying notes are an integral part of these consolidated financial statements.
F-3
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE)
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1998 1997 1996
-------------- ------------- --------------
REVENUES
Oil and gas sales........................................ $ 51,932 $ 70,929 $ 60,610
Natural gas services..................................... 3,795 4,559 4,281
-------------- ------------- --------------
Total revenues....................................... 55,727 75,488 64,891
-------------- ------------- --------------
COSTS AND EXPENSES
Lease operations......................................... 14,237 16,205 14,776
Exploration:
Abandonments and impairments......................... 16,128 2,692 597
Seismic and other.................................... 4,501 7,629 1,036
Natural gas services..................................... 3,242 3,955 3,437
Depreciation, depletion and amortization................. 31,665 31,273 23,758
Impairment of property and equipment..................... 8,493 236 1,186
General and administrative............................... 4,299 4,181 3,266
-------------- ------------- --------------
Total costs and expenses............................. 82,565 66,171 48,056
-------------- ------------- --------------
Operating income (loss).............................. (26,838) 9,317 16,835
-------------- ------------- --------------
OTHER INCOME (EXPENSE)
Interest expense......................................... (2,384) (1,767) (3,440)
Other.................................................... 138 217 335
-------------- ------------- --------------
Total other income (expense)......................... (2,246) (1,550) (3,105)
-------------- ------------- --------------
INCOME (LOSS) BEFORE INCOME TAXES............................. (29,084) 7,767 13,730
-------------- ------------- --------------
INCOME TAX EXPENSE
Current.................................................. - - -
Deferred................................................. - - -
-------------- ------------- --------------
Total income tax expense............................. - - -
-------------- ------------- --------------
NET INCOME (LOSS)............................................. $ (29,084) $ 7,767 $ 13,730
============== ============= ==============
Net income (loss) per common share:
Basic.................................................... $ (3.27) $ .87 $ 1.80
============== ============= ==============
Diluted.................................................. $ (3.27) $ .85 $ 1.76
============== ============= ==============
Weighted average common shares outstanding:
Basic.................................................... 8,905 8,888 7,624
============== ============= ==============
Diluted.................................................. 8,905 9,094 7,800
============== ============= ==============
The accompanying notes are an integral part of these consolidated financial statements.
F-4
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
COMMON STOCK
------------------ ADDITIONAL RETAINED
NO. OF PAR PAID-IN EARNINGS TREASURY
SHARES VALUE CAPITAL (DEFICIT) STOCK TOTAL
------ -------- --------- --------- --------- ---------
BALANCE,
December 31, 1995 .................. 7,410 $ 741 $ 52,912 $(18,657) $ - $ 34,996
Sale of stock through secondary
public offering, net of
offering costs ............... 1,428 143 16,874 - - 17,017
Issuance of stock through
compensation plans ........... 90 9 462 - - 471
Net income .................... - - - 13,730 - 13,730
-------- -------- -------- -------- -------- --------
BALANCE,
December 31, 1996 .................. 8,928 893 70,248 (4,927) - 66,214
Repurchase of common stock
for treasury ................ - - - - (1,520) (1,520)
Issuance of stock through
compensation plans ........... 53 5 608 - - 613
Net income .................... - - - 7,767 - 7,767
-------- -------- -------- -------- -------- --------
BALANCE,
December 31, 1997 .................. 8,981 898 70,856 2,840 (1,520) 73,074
Cancellation of treasury stock (95) (9) (1,511) - 1,520 -
Issuance of stock through
compensation plans ........... 52 5 399 - - 404
Net loss ...................... - - - (29,084) - (29,084)
-------- -------- -------- -------- -------- --------
BALANCE,
December 31, 1998 .................. 8,938 $ 894 $ 69,744 $(26,244)$ - $ 44,394
======== ======== ======== ======== ======== ========
The accompanying notes are an integral part of these consolidated financial statements.
F-5
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1998 1997 1996
-------------- ------------- --------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)........................................ $ (29,084) $ 7,767 $ 13,730
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization............. 31,665 31,273 23,758
Impairment of property and equipment................. 8,493 236 1,186
Exploration costs.................................... 16,128 2,692 597
Gain on sales of property and equipment.............. (53) (155) (293)
Other................................................ 375 582 445
Changes in operating working capital:
Accounts receivable.................................. 2,842 (1,088) (3,871)
Accounts payable..................................... 1,448 766 4,824
Other................................................ 1,691 (2,749) (70)
-------------- ------------- --------------
Net cash provided by operating activities....... 33,505 39,324 40,306
-------------- ------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment...................... (53,720) (56,167) (33,100)
Proceeds from sales of property and equipment............ 260 303 3,862
-------------- ------------- --------------
Net cash used in investing activities........... (53,460) (55,864) (29,238)
-------------- ------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt............................. 19,200 17,700 -
Repayments of long-term debt............................. - - (26,935)
Repurchase of common stock for treasury.................. - (1,520) -
Proceeds from sale of common stock....................... 29 31 17,043
-------------- ------------- --------------
Net cash provided by (used in) financing
activities..................................... 19,229 16,211 (9,892)
-------------- ------------- --------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS............................................. (726) (329) 1,176
CASH AND CASH EQUIVALENTS
Beginning of period...................................... 2,150 2,479 1,303
-------------- ------------- --------------
End of period............................................ $ 1,424 $ 2,150 $ 2,479
============== ============= ==============
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts
capitalized............................................. $ 2,291 $ 1,668 $ 3,434
============== ============= ==============
The accompanying notes are an integral part of these consolidated financial statements.
F-6
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS
Clayton Williams Energy, Inc. and its subsidiaries (collectively, the
"Company") is an independent oil and gas company engaged in the exploration for
and development and production of oil and natural gas primarily in South and
East Texas, Southeastern New Mexico, the Texas Gulf Coast, Louisiana and
Mississippi.
Substantially all of the Company's oil and gas production is sold under
short-term contracts which are market-sensitive. Accordingly, the Company's
financial condition, results of operations, and capital resources are highly
dependent upon prevailing market prices of, and demand for, oil and natural gas.
These commodity prices are subject to wide fluctuations and market uncertainties
due to a variety of factors that are beyond the control of the Company. These
factors include the level of global demand for petroleum products, foreign
supply of oil and gas, the establishment of and compliance with production
quotas by oil-exporting countries, weather conditions, the price and
availability of alternative fuels, and overall economic conditions, both foreign
and domestic. From time to time, the Company utilizes hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure to
price fluctuations (see Note 9).
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. 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 individually 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.
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.
F-7
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 consists primarily of field equipment and facilities, office
equipment, leasehold improvements and vehicles. 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 other income in the accompanying consolidated
statements 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 39 years.
VALUATION OF PROPERTY AND EQUIPMENT
The Company follows the provisions of Statement of Financial Accounting
Standards No. 121 "Accounting for Impairment of Long-Lived Assets" ("SFAS 121"),
which requires that the Company's long-lived assets, including its oil and gas
properties, be assessed for potential impairment in their carrying values
whenever events or changes in circumstances indicate such impairment may have
occurred.
SFAS 121 provides for future revenue from the Company's oil and gas
production to be estimated at prices at which management predicts such products
will be sold. In evaluating its oil and gas properties for impairment at
December 31, 1998, management has estimated such future product prices at levels
which it believes are reasonable and supportable, but which exceed the current
market prices for oil and gas. Any downward revisions to management's estimates
of product prices could result in additional impairments of its oil and gas
properties in future periods.
INCOME TAXES
The Company follows the asset and liability method prescribed by
Statement of Financial Accounting Standards No. 109 "Accounting for Income
Taxes" ("SFAS 109"). Under this method of accounting for income taxes, 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.
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. During the years ended December
31, 1998, 1997 and 1996, the Company capitalized interest totaling approximately
$967,000, $346,000 and $68,000, respectively.
STATEMENTS OF CASH FLOWS
The Company considers all highly liquid investments with original
maturities of three months or less to be cash equivalents.
F-8
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NET INCOME (LOSS) PER COMMON SHARE
The Company computes net income (loss) per common share in accordance
with Statement of Financial Accounting Standards No. 128 "Earnings Per Share"
("SFAS 128"). Basic net income (loss) per common share is based on the weighted
average number of common shares outstanding during each period. Diluted net
income (loss) per share gives further effect to the additional dilution, if any,
related to outstanding employee stock options. Because the Company reported a
net loss in 1998, the effects of outstanding employee stock options were
anti-dilutive.
STOCK-BASED COMPENSATION
The Company accounts for stock-based compensation utilizing the intrinsic
value method prescribed by Accounting Principles Board Opinion No. 25
"Accounting for Stock Issued to Employees" ("APB 25").
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 did not have any significant imbalance positions at December 31, 1998,
1997 or 1996.
3. LONG-TERM DEBT
Long-term debt consists of the following:
DECEMBER 31,
------------------------------
1998 1997
------------- -------------
(IN THOUSANDS)
Secured Bank Credit Facility (matures July 31, 2001)................ $ 54,900 $ 35,700
Other............................................................... - 42
------------- -------------
54,900 35,742
Less current maturities............................................. 15,800 42
------------- -------------
$ 39,100 $ 35,700
============= =============
Aggregate maturities of long-term debt at December 31, 1998 are as
follows: 1999 - $15,800,000; 2000 - $7,800,000; and 2001 - $31,300,000.
SECURED BANK CREDIT FACILITY
The Company's secured bank credit facility provides for a revolving loan
facility in an amount not to exceed the lesser of the borrowing base, as
established by the banks, or that portion of the borrowing base determined by
the Company to be the elected borrowing limit. At December 31, 1998, the
borrowing base was $57 million and the outstanding advances were $54.9 million.
In January 1999, the borrowing base was reduced to $53 million to give effect to
the sale of certain assets in Matagorda County, Texas. The borrowing base, which
is based on the discounted present value of future net revenues from oil and gas
production, is subject to redetermination at any time, but at least
semi-annually, and is made at the discretion of the banks. Substantially all of
the Company's oil and gas properties are pledged to secure advances under the
credit facility.
In March 1999, the banks completed a borrowing base review and elected to
maintain the borrowing base at $53 million until the Company consummates the
sale of its Jalmat assets (see Note 4). Once the Jalmat sale is completed, the
borrowing base will reduce to $43 million and will also be subject to monthly
commitment reductions of $650,000 beginning in July 1999. The adjusted borrowing
base will remain in effect until the next scheduled borrowing base
redetermination in November 1999. Based on these amended terms, the Company will
be required to repay $15.8 million of indebtedness on the credit facility
F-9
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
in 1999 and has reclassified that amount as a current liability in the
accompanying consolidated balance sheet. However, if the Jalmat sale does not
occur by May 1, 1999, the banks will cause the borrowing base to be
redetermined. If the redetermined borrowing base is less than the amount of
outstanding indebtedness, the Company will be required to (i) pledge
additional collateral, (ii) prepay the excess in not more than five equal
monthly installments, or (iii) elect to convert the entire amount of
outstanding indebtedness to a term obligation based on amortization formulas
set forth in the loan agreement.
If funds available from asset sales, combined with operating cash
flow, are not sufficient to fund its debt repayments and anticipated levels
of capital expenditures, the Company will be required to seek alternative
forms of capital resources, including the sale of other assets and the
issuance of debt or equity securities. Although the Company believes it will
be able to obtain funds pursuant to one or more of these alternatives, if
needed, management cannot be assured that any such capital resources will be
available to the Company. If additional capital resources are needed, but the
Company is unable to obtain such capital resources on a timely basis, the
Company may not be able to maintain a level of liquidity sufficient to meet
its obligations as they mature or remain in compliance with the required
financial covenants contained in the credit facility.
All outstanding balances on the credit facility may be designated, at
the Company's option, as either "Base Rate Loans" or "Eurodollar Loans" (as
defined in the loan agreement), provided that not more than two Eurodollar
traunches may be outstanding at any time. Base Rate Loans bear interest at
the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 3/8% per
annum, depending on levels of outstanding advances and letters of credit.
Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin
ranging from 1.75% to 2.5% per annum (as amended in March 1999). At December
31, 1998, the Company's indebtedness under the credit facility consisted of
$48 million of Eurodollar Loans at a rate of 7.1% and $6.9 million of Base
Rate Loans at a rate of 8.1%.
In addition, the Company pays the banks a commitment fee equal to 1/4%
per annum on the unused portion of the revolving loan commitment. Interest on
the revolving loan and commitment fees are payable quarterly, and all
outstanding principal and interest will be due July 31, 2001.
The loan agreement contains financial covenants that are computed
quarterly and require the Company to maintain minimum levels of working
capital, cash flow and net tangible assets. In March 1999, the Company and
the banks amended the loan agreement with respect to the computations
required for the fourth quarter of 1998 and all quarters in 1999. The Company
was in compliance with all of the adjusted financial covenants at December
31, 1998.
4. PROPERTY HELD FOR RESALE
At December 31, 1998, the Company had identified two properties for
sale in 1999. In January 1999, the Company completed the sale of its interest
in eight non-operated oil and gas wells located in Matagorda County, Texas
for $5.2 million. In March 1999, the Company entered into a definitive
agreement for the sale of its interests in the Jalmat Field located in Lea
County, New Mexico for $12.5 million. The Jalmat sale is scheduled to close
in April 1999. Proceeds from these sales will be used to reduce indebtedness
on the secured bank credit facility. The net book value of these properties
aggregating $7.5 million has been classified as a current asset in the
accompanying consolidated balance sheet.
5. STOCKHOLDERS' EQUITY
In November 1996, the Company received $17,017,000, net of
underwriter's discounts and other offering costs totaling $1,541,000, from
the sale of 1,427,500 shares of common stock to the public at a
F-10
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
price of $13.00. Proceeds from the offering were used to repay indebtedness
on the secured bank credit facility.
In January 1997, the Company repurchased shares of its common stock on
the open market at a cost of $1,520,000.
In June 1998, the Company cancelled the 95,000 shares of its common
stock held as treasury stock. The cost of the cancelled shares, which totaled
$1,520,000, was reclassified as a reduction in common stock and additional
paid-in capital.
6. EARNINGS PER SHARE
In 1997, the Company adopted SFAS 128, which changes the method of
computing and disclosing earnings per share for periods ending after December
15, 1997. In accordance with SFAS 128, basic earnings per common share was
computed by dividing net income (loss) by the weighted average number of
shares of common stock outstanding during the period. Diluted earnings per
common share was computed by including the dilutive effect, if any, of
outstanding employee stock options utilizing the treasury stock method. All
prior periods have been restated to give effect to the adoption of SFAS 128,
the impact of which was immaterial. For all periods presented, the
differences between basic shares and diluted shares were attributable to the
dilutive effect of employee stock options.
7. STOCK COMPENSATION PLANS
1993 PLAN
The Company has reserved 898,200 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 through December 31, 1998 expire 10 years from the date of
grant and become exercisable based on varying vesting schedules.
The following table reflects activity in the 1993 Plan for 1998, 1997 and
1996.
1998 1997 1996
-------------------------- -------------------------- ---------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES PRICE SHARES PRICE SHARES PRICE
------- -------- ------- -------- ------- --------
Beginning of year..... 632,269 $10.99 458,766 $8.46 151,601 $2.45
Granted (a)...... 110,168 $11.61 210,700 $15.36 321,500 $11.03
Exercised........ (12,305) $2.39 (12,791) $2.53 (10,410) $2.38
Forfeited........ (8,080) $11.69 (24,406) $5.53 (3,925) $2.82
----------- ----------- -----------
End of year........... 722,052 $11.23 632,269 $10.99 458,766 $8.46
=========== =========== ===========
Exercisable........... 261,089 $7.72 194,357 $6.00 104,449 $2.47
=========== =========== ===========
Issuable.............. 176,148 265,931 439,434
=========== =========== ===========
(a) The Company granted new options as follows: 1998 - 102,168 shares at $11.69
per share, 3,000 shares at $9.06 per share, and 5,000 shares at $11.50 per
share; 1997 - 48,700 shares at $14.00 per share, 12,000 shares at $14.44
per share, and 150,000 shares at $15.88 per share; and 1996 - 121,500
shares at $3.25 per share and 200,000 shares at $15.75 per share.
F-11
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 18,000 shares of
common stock (3,000 per year from 1993 through 1998) at option prices ranging
from $3.25 to $18.50 per share. All options expire 10 years from the date of
grant and are fully exercisable upon issuance. At December 31, 1998, options to
purchase 18,000 shares were outstanding, and 68,300 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. In November 1997, cash awards totaling $31,500 and stock
awards totaling 9,310 shares of common stock at a market price of $16.00 per
share were granted to certain employees and officers. At December 31, 1998,
106,190 shares remain available for issuance 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, permitting 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 reserved an aggregate of 650,000 shares of common stock for
issuance under these plans. During 1998, 1997 and 1996, the Company issued
28,789, 30,808 and 67,785 shares, respectively, of common stock to one officer
in lieu of cash compensation aggregating $278,000, $421,000 and $384,000,
respectively. Three outside directors were issued 690 shares in 1997 and 11,581
shares in 1996 in lieu of cash compensation aggregating $12,000 and $61,000,
respectively. The amounts of such compensation are included in general and
administrative expense in the accompanying consolidated financial statements.
The Company terminated the outside directors stock compensation plan in January
1997.
SUPPLEMENTAL DISCLOSURE
In October 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123 "Accounting for Stock-Based
Compensation" ("SFAS 123"). SFAS 123 establishes a fair value method and
disclosure standards for stock-based employee compensation arrangements, such as
stock option plans. As permitted by SFAS 123, the Company has elected to
continue following the provisions of APB 25 for such stock-based compensation,
under which no compensation expense has been recognized. Had compensation
expense for these plans been determined consistent with SFAS 123, the Company's
net income (loss) and net income (loss) per share would have been as follows:
1998 1997 1996
----------- ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE)
Net income (loss):
As reported.............................................. $ (29,084) $ 7,767 $ 13,730
Pro forma................................................ $ (30,172) $ 7,175 $ 13,558
Net income (loss) per share:
Basic:
As reported.......................................... $ (3.27) $ .87 $ 1.80
Pro forma............................................ $ (3.39) $ .81 $ 1.78
Diluted:
As reported.......................................... $ (3.27) $ .85 $ 1.76
Pro forma............................................ $ (3.39) $ .79 $ 1.74
F-12
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
SFAS 123 requires the use of option valuation models which were generally
developed for use in estimating the fair value of traded options which have no
vesting restrictions, are fully transferable and generally have shorter life
expectancies. These valuation models also require the input of highly subjective
assumptions, including the expected stock price volatility. Because the
Company's stock option plans have characteristics significantly different from
those of traded options, and because changes in the subjective input assumptions
can materially affect the fair value estimate, in management's opinion, the
existing models do not necessarily provide a reliable single measure of the fair
value of its employee stock options.
For purposes of the above pro forma disclosures, the fair value of each
option grant is estimated as of the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions for grants in
1998, 1997, and 1996, respectively: risk-free interest rates of 5.2%, 6.1%, and
5.8%; dividend yields of 0%; volatility factors of the expected market price of
the Company's common stock of .55, .575, and .561; and a life expectancy of each
option of 10, 7, and 5.1 years.
8. TRANSACTIONS WITH AFFILIATES
During the periods presented, the Company and various entities controlled
by the Company's principal stockholder provided certain general and
administrative services to one another. General and administrative expenses in
the accompanying financial statements are net of charges by the Company to
affiliates for services aggregating $664,000, $684,000, and $615,000 for the
years ended December 31, 1998, 1997 and 1996, respectively, and include charges
to the Company by affiliates for rents and services aggregating $102,000,
$200,000 and $235,000 for the years ended December 31, 1998, 1997 and 1996,
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.
9. 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 $345,000, $337,000 and $398,000 for the years ended December 31,
1998, 1997 and 1996, respectively. Included in property and equipment are assets
under capital leases aggregating $33,000 and $133,000, net of accumulated
depreciation, at December 31, 1997 and 1996, respectively.
Future minimum payments under noncancelable leases at December 31, 1998,
are as follows:
OPERATING
LEASES
------------------
(IN THOUSANDS)
1999............................................. $ 550
2000............................................. 500
2001............................................. 434
Thereafter....................................... 72
------------------
Total minimum lease payments.............. $ 1,556
==================
F-13
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (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.
HEDGING ACTIVITIES
From time to time, the Company utilizes forward sale and other financial
option arrangements, such as swaps and collars, to reduce price risks on the
sale of its oil and gas production. The Company accounts for such arrangements
as hedging activities and, accordingly, records all realized gains and losses as
oil and gas revenues in the period the hedged production is sold. Included in
oil and gas revenues are net gains totaling $9,871,000 in 1998 (comprised of
gains of $10,024,000, partially offset by losses of $153,000), gains totaling
$252,000 in 1997, and net losses totaling $1,156,000 in 1996 (comprised of
losses of $1,299,000 partially offset by gains of $143,000). As of December 31,
1998, the Company had realized losses aggregating $102,000 on early terminations
of swap arrangements covering 750,000 MMbtu of its gas production from January
1999 to May 1999. These losses will be recognized during 1999 as the hedged
production is sold. The Company also had options to sell an aggregate of 800,000
barrels of oil production for the period from January 1999 through June 1999 at
a price of $10.00. The cost of these options of $208,000 will be recognized
during 1999 as the hedged production is sold.
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.
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.
10. IMPAIRMENT OF PROPERTY AND EQUIPMENT
During 1996, the Company recorded a provision for impairment of property
and equipment under SFAS 121 totaling $1.2 million resulting from a revision in
reserve estimates subsequent to December 31, 1995, attributable to a proved
undeveloped location in the Texas Gulf Coast area. In 1997, the Company recorded
an additional provision for impairment under SFAS 121 of $236,000 attributable
to certain minor-value properties.
During 1998, the Company recorded a provision for impairment under SFAS
121 of $8.5 million attributable to certain oil and gas properties in east
central Texas, south Texas, the Texas Gulf Coast and Louisiana. The impairment
was caused primarily by a decline in forecasted oil and gas prices. Fair market
value of the impaired assets was estimated to be the present value of expected
future cash flows at an appropriate discount rate.
F-14
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. PURCHASES AND SALES 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. The net proceeds were used to repay indebtedness on the secured
bank credit facility. No gain or loss was recognized on the sale.
In October 1998, the Company purchased certain oil and gas properties in
north Texas for $1.8 million with an effective date of September 1, 1998.
In November 1998, the Company and an affiliated limited partnership
acquired certain oil and gas properties in east Texas for an aggregate purchase
price of $41.2 million, net of closing adjustments. The effective date for
accounting purposes was December 1, 1998. All revenues and expenses subsequent
to the stated effective date of April 1, 1998 but prior to December 1, 1998 were
accounted for as adjustments to the purchase price. The Company acquired an
undivided 10% interest in the purchased assets for $4.9 million of the adjusted
purchase price. In addition, the Company serves as general partner of the
limited partnership which acquired the remaining 90%. After the limited partner
receives an agreed-upon rate of return, the Company's general partnership
interest will increase from 1% to 35%.
12. INCOME TAXES
Since the Company's consolidation in May 1993, the Company has
incurred net losses for financial reporting purposes aggregating $26.2
million and has recognized cumulative tax losses of approximately $35 million
which can be carried forward and used to offset future taxable income. Tax
loss carryforwards begin to expire in 2008. Due to the uncertainty of
realizing the related future benefits from tax loss carryforwards, valuation
allowances have been recorded to the extent net deferred tax assets exceed
net deferred tax liabilities at December 31, 1998, 1997 and 1996.
The tax effected temporary differences and tax loss carryforwards which
comprise net deferred tax assets and liabilities are as follows:
DECEMBER 31,
----------------------------------------------------
1998 1997 1996
--------------- ---------------- ---------------
(IN THOUSANDS)
Deferred tax assets (liabilities):
Depreciable and depletable property.............. $ (2,394) $ (12,828) $ (10,216)
Tax loss carryforwards........................... 12,295 12,584 12,737
Other............................................ 970 936 929
Valuation allowance.............................. (10,871) (692) (3,450)
--------------- ---------------- ---------------
Net deferred tax asset (liability)............ $ - $ - $ -
=============== ================ ===============
All of the differences between the statutory income tax rates and the
effective income tax rates are attributable to the change in the valuation
allowance.
13. RECENT ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130 "Reporting Comprehensive Income"
("SFAS 130"). SFAS 130 establishes standards for reporting and displaying of
comprehensive income and its components (revenue, expenses, gains and losses) in
a full set of general-purpose financial statements. For the years ended December
31, 1998, 1997 and 1996, the Company reported no differences between
comprehensive income and net income.
F-15
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and
reporting standards for derivative instruments and hedging activities. It
requires that derivatives be recognized as assets or liabilities and measured at
their fair value. SFAS 133 will be adopted in 2000 and is not expected to have a
material effect on the Company's financial condition or operations.
14. 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:
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1998 1997 1996
--------------- ---------------- ---------------
(IN THOUSANDS)
Property acquisitions:
Proved................................. $ 7,077 $ - $ 1,375
Unproved............................... 10,602 14,042 5,002
Developmental costs........................... 7,285 32,656 20,931
Exploratory costs............................. 22,319 13,813 6,306
--------------- ---------------- ---------------
Total.................................. $ 47,283 $ 60,511 $ 33,614
=============== ================ ===============
The following table sets forth the capitalized costs for oil and gas
properties:
DECEMBER 31,
------------------------------
1998 1997
------------- -------------
(IN THOUSANDS)
Proved properties................................................... $ 415,471 $ 393,672
Unproved properties................................................. 8,889 18,680
------------- -------------
Total capitalized costs............................................. 424,360 412,352
Accumulated depreciation, depletion and
amortization...................................................... (328,231) (300,569)
------------- -------------
Net capitalized costs........................................ $ 96,129 $ 111,783
============= =============
15. 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
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (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 MBOE at one
MBbl per six MMcf):
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------------------
1998 1997 1996
----------------------------- ----------------------------- -----------------------------
Oil Gas MBOE Oil Gas MBOE Oil Gas MBOE
------- ------- ------- ------- ------- ------- ------- ------- -------
Proved reserves
Beginning of period .......... 8,410 32,861 13,887 8,507 35,798 14,474 5,963 39,496 12,546
Revisions .................... (744) (3,248) (1,285) (726) 1,020 (556) 457 (2,359) 64
Extensions and discoveries ... 254 8,768 1,716 3,532 1,134 3,721 4,077 113 4,096
Purchases of minerals-in-place 349 5,306 1,233 - - - 213 4,132 902
Production ................... (2,528) (4,833) (3,334) (2,903) (5,091) (3,752) (2,203) (5,584) (3,134)
------- ------- ------- ------- ------- ------- ------- ------- -------
End of period ................ 5,741 38,854 12,217 8,410 32,861 13,887 8,507 35,798 14,474
======= ======= ======= ======= ======= ======= ======= ======= =======
Proved developed reserves
Beginning of period .......... 7,826 27,392 12,392 7,199 30,496 12,282 5,381 31,668 10,659
======= ======= ======= ======= ======= ======= ======= ======= =======
End of period ................ 5,504 32,215 10,873 7,826 27,392 12,392 7,199 30,496 12,282
======= ======= ======= ======= ======= ======= ======= ======= =======
The standardized measure of discounted future net cash flows relating to
proved reserves was as follows:
DECEMBER 31,
-------------------------------------------------
1998 1997 1996
-------------- ------------- --------------
(IN THOUSANDS)
Future cash inflows........................................... $ 128,149 $ 219,528 $ 342,576
Future costs:
Production............................................. (43,647) (67,207) (93,359)
Development............................................ (9,999) (13,445) (15,543)
Income taxes........................................... - (10,445) (50,508)
-------------- ------------- --------------
Future net cash flows......................................... 74,503 128,431 183,166
10% discount factor........................................... (22,442) (36,028) (47,453)
-------------- ------------- --------------
Standardized measure of discounted future net cash flows...... $ 52,061 $ 92,403 $ 135,713
============== ============= ==============
Changes in the standardized measure of discounted future net cash flows
relating to proved reserves were as follows:
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1998 1997 1996
-------------- ------------- --------------
(IN THOUSANDS)
Standardized measure, beginning of period..................... $ 92,403 $ 135,713 $ 88,830
Net changes in sales prices, net of production costs.......... (31,210) (49,024) 56,812
Revisions of quantity estimates............................... (6,103) (4,376) 811
Accretion of discount......................................... 9,992 16,067 8,883
Changes in future development costs, including
development costs incurred that reduced future
development costs............................................ 8,415 8,622 5,713
Changes in timing and other................................... (2,758) (874) (887)
Net change in income taxes.................................... 7,515 17,442 (24,957)
Extensions and discoveries.................................... 7,165 23,557 38,703
Sales, net of production costs................................ (37,695) (54,724) (45,834)
Purchases of minerals-in-place................................ 4,337 - 7,639
-------------- ------------- --------------
Standardized measure, end of period........................... $ 52,061 $ 92,403 $ 135,713
============== ============= ==============
F-17
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF EXHIBIT
------- -------------------------------------------------------------
10.2 First Amendment to Sixth Restated Loan Agreement dated as of
November 20, 1998, among Clayton Williams Energy, Inc.,
Warrior Gas Co., CWEI Acquisitions, Inc., Bank One, Texas,
N.A., Paribas, Union Bank of California, N.A., and Compass Bank
10.3 Second Amendment to the Sixth Restated Loan Agreement dated
as of March 26, 1999, among Clayton Williams Energy, Inc.,
Warrior Gas Co., CWEI Acquisitions, Inc., Bank One, Texas,
N.A., Paribas and Union Bank of California, N.A.
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Williamson Petroleum Consultants, Inc.
24.1 Power of Attorney
24.2 Certified copy of resolution of Board of Directors of
Clayton Williams Energy, Inc. authorizing signature pursuant
to Power of Attorney
27 Financial Data Schedules for the year ended December 31,
1998