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, 1999
|_| 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
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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
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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
22, 2000, 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 $65,489,076.
There were 9,176,199 shares of Common Stock, $.10 par value, of the
registrant outstanding as of March 22, 2000.
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, 2000. 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") is an
independent oil and gas company engaged in the exploration for and development
and production of oil and natural gas primarily in Texas, Louisiana and New
Mexico. A significant portion of the Company's proved oil and gas reserves are
concentrated in the Cretaceous Trend (the "Trend"), which extends from south
Texas through east Texas, Louisiana and other southern states and includes the
Austin Chalk, Buda, and Georgetown formations. Although low oil prices caused
the Company to temporarily suspend Trend drilling activities from April 1998
through September 1999, the Company is currently drilling horizontal wells in
this area and is also conducting secondary water frac operations on existing
Trend wells.
Since 1997, the Company has initiated several exploratory projects
designed to reduce its dependence on Trend drilling for future production and
reserve growth. These new areas include the Company's Cotton Valley Pinnacle
Reef exploratory project, which targets deep gas structures in the vicinity of
its core properties in east central Texas, as well as other exploratory projects
in south Texas, Louisiana and Mississippi.
As of December 31, 1999, the Company had estimated proved reserves
totaling 11,904 MBbls of oil and 30.1 Bcf of gas with $176.5 million of
estimated future net revenues before income taxes (discounted at 10% and based
on year-end prices). During 1999, the Company added 4,790 MBOE of estimated
proved reserves through extensions and discoveries, 54% of which were classified
as proved undeveloped reserves at December 31, 1999. The Company held interests
in 496 gross (283.4 net) oil and gas wells and owned leasehold interests in
408,944 gross (221,948 net) undeveloped acres at December 31, 1999.
1
During 1999, the Company sold its interest in eight non-operated oil and
gas wells located in Matagorda County, Texas for $5.2 million and sold all of
its interests in the Jalmat Field located in Lea County, New Mexico for $12.5
million. Proceeds from these sales were used to reduce the amount of outstanding
indebtedness on the Company's secured bank credit facility. See "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 1999, together with its plans for
capital and exploratory expenditures in 2000. Under current economic conditions,
the Company presently plans to spend $43 million on exploration and development
activities during 2000. The Company may increase or decrease its planned
activities for 2000, depending upon drilling results, product prices, the
availability of capital resources, and other factors affecting the economic
viability of such activities.
The Trend
The Company holds a 113,000 net acre lease block (the "North Giddings
Block") in the updip area of the Giddings Field in Burleson, Robertson and Milam
Counties, Texas. In addition to Trend drilling potential, a significant portion
of the acreage in the North Giddings Block is also prospective for Cotton Valley
Pinnacle Reef exploration activities (see "Cotton Valley Exploratory Project").
The Company has developed more than half of this acreage by the drilling of 112
gross (108.2 net) horizontal Trend wells through December 31, 1999.
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 and the first half of 1999, the Company
suspended its Trend drilling activities from April 1998 through September 1999.
As a result, capital expenditures on Trend drilling and leasing activities in
1999 totaled $7.8 million, as compared to $9.1 million in 1998 and $44.1 million
in 1997. The suspension of Trend drilling contributed significantly to declines
in oil production from 1997 levels.
Oil prices have increased dramatically in recent months, and accordingly,
the Company has resumed drilling activities in the Trend. However, based upon
the production performance of wells previously drilled by the Company in the
southern portion of the North Giddings Block, the Company does not currently
believe that the reserve potential in this area is sufficient to justify a
multiple-well drilling program on the remaining undeveloped acreage. Instead,
the Company plans to spend approximately $11.8 million during the current year
to further exploit the developed portion of its Trend acreage by drilling new
horizontal wells in areas that warrant development on an increased density basis
and by conducting secondary water frac operations on existing wells. Trend
drilling and water frac activities accounted for approximately 67% of the 4,790
MBOE of proved reserves added in 1999 through extensions and discoveries, most
of which were classified as proved undeveloped reserves at December 31, 1999.
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, 1999, the Company had interests in 268 gross (204.3 net) producing wells in
the Giddings Field, including 198 horizontal and 70 vertical wells. For the year
ended December 31, 1999, the Company's daily net production in the Giddings
Field averaged approximately 4,672 Bbls of oil and 4,844 Mcf of gas. The Company
operates 82% of its wells in the Giddings Field.
2
Cotton Valley Exploratory Project
The Company is actively exploring for gas reserves in the prolific Cotton
Valley Pinnacle Reef play on a portion of its acreage in the North Giddings
Block in Robertson County, Texas. As 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 below 15,000 feet. During 1999, the Company
spent $8.1 million on drilling, leasing and seismic activities related to the
Cotton Valley Exploratory Project and completed construction of certain gas
gathering and processing systems in the area. The Company completed the J. C.
Fazzino Unit #1 into the edge of one of the anomalies identified by a 3-D
seismic survey and drilled and completed the J. C. Fazzino Unit #2 to the center
of the same anomaly. Although the Company owns all of the working interest in
both wells, the Fazzino #2 was drilled pursuant to a non-recourse vendor
financing arrangement which grants to participating vendors an overriding
royalty interest in approximately 40% of the production from the Fazzino #2, and
any subsequent wells drilled under this arrangement, until payout (plus an
agreed-upon rate of return).
As of December 31, 1999, the Company's net remaining gas reserves
attributable to the Fazzino #1 and Fazzino #2 were approximately 2.9 Bcf and 7.3
Bcf, respectively, as estimated by the Company's independent engineers based on
guidelines established by the Securities and Exchange Commission. The process of
estimating oil and gas reserves is complex and requires significant decisions
and assumptions in the evaluation of available geological, geophysical,
engineering and economic data. As a result, such estimates are inherently
imprecise, particularly with respect to wells such as the Fazzino #1 and the
Fazzino #2 where the production history is limited and the production rates have
been restricted by plant capacity. Therefore, these reserve estimates are
subject to downward or upward revisions based upon future production
performance, and the amount of any such revisions may have a material effect on
the Company's total proved oil and gas reserves (see "Properties - Reserves").
In December 1999, the Company began drilling the Varisco Estate #1, a
16,400 foot test of the second reef anomaly which the Company expects to
complete in April 2000. In addition, the Company has begun drilling operations
on the McGrew #1, a 17,000 foot test of the third reef anomaly. Both the Varisco
Estate #1 and the McGrew #1 are being drilled pursuant to the same vendor
financing arrangement as the Fazzino #2.
The Company plans to spend approximately $12 million during 2000 on
drilling, leasing and seismic activities in connection with the Cotton Valley
Exploratory Project, including the construction of a 70,000 Mcf per day gas
treating plant with a scheduled start-up date of April 1, 2000. Currently, the
Company is unable to produce the Fazzino #1 and the Fazzino #2 at their optimum
production rates due to limited plant capacity. However, once the new gas plant
is operational, the Company expects to have adequate processing capacity to
accommodate the planned expansion of its Pinnacle Reef production base for the
near term.
Other Exploration and Development Activities
Louisiana
The Company spent $2.5 million during 1999 on various exploratory
prospects in Louisiana, including costs to drill exploratory wells, conduct
seismic surveys and acquire leases. The Company drilled 3 gross (1.6 net)
exploratory wells in Louisiana during 1999, of which 1 gross well (.6 net) was
completed as an oil discovery. The Company also successfully completed a third
well in this area in February 2000. The Company plans to spend $9.8 million in
Louisiana during 2000 primarily on prospects being identified by 3-D seismic
data to which the Company has access through a negotiated arrangement with a
geophysical service company.
3
New Mexico
The Company plans to spend approximately $5.8 million during 2000 to drill
and complete 12 developmental oil wells in Eddy County, New Mexico. These wells
will be completed in two zones, the Yeso formation at a depth of about 4,000
feet and also in the Grayburg San Andres formation at depths ranging from 2,500
feet to 3,700 feet.
Partnership Management
The Company serves as general partner of a limited partnership which the
Company formed in 1998 to facilitate the acquisition of certain oil and gas
properties in east Texas. The Company acquired an undivided 10% interest in the
purchased assets for $4.9 million, and the partnership acquired the remaining
90% for $36.2 million. After the limited partner receives an agreed-upon rate of
return, the Company's general partnership interest will increase from 1% to 35%.
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 formulas 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 six gas gathering systems and
six gas processing plants in the states of Texas and Mississippi. These natural
gas service facilities consist of interests in approximately 70 miles of
pipeline, five treating plants (one of which is a 70,000 Mcf per day gas
treating plant currently being constructed in connection with the Company's
Cotton Valley Pinnacle Reef play), 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 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.
4
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 various orders, culminating in its Order No. 636 series, that have
significantly altered the marketing and transportation of gas. These orders
resulted in 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. These FERC actions were designed
to increase competition within all phases of the gas industry. It is difficult
to predict the net impact on the Company of these revised marketing rules. The
interstate regulatory framework may enhance the Company's ability to market and
transport its gas, although it may also subject the Company to greater
competition and to the 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. The
FERC has implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such rate
to inflation, subject to certain conditions and limitations. These regulations
could increase the cost of transporting oil and natural gas liquids by pipeline.
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. 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
5
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, if adopted, 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 in the future to prohibit the discharge of produced
water and sand and some other substances related to the oil and gas industry,
into 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.
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.
6
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 87 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.
7
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,
1999, the Company had interests in 496 gross (283.4 net) oil and gas wells and
owned leasehold interests in 408,944 gross (221,948 net) undeveloped acres.
Reserves
The following table sets forth certain information as of December 31, 1999
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
--------- ----------- -----
Oil (MBbls) .......................... 9,028 2,876 11,904
Gas (MMcf) ........................... 26,960 3,181 30,141
MBOE ................................. 13,521 3,407 16,928
PV-10 Value:
Before income taxes ............ $148,705 $ 27,795 $176,500
After income taxes ............. $151,642
The following table sets forth certain information as of December 31, 1999
regarding the Company's proved oil and gas reserves in each of its principal
producing areas.
Proved Reserves Percentage of
------------------------------ 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 ............ 11,302 9,950 12,960 76.6% $143,827 81.4%
Cotton Valley .... -- 10,177 1,696 10.0% 17,110 9.7%
East Texas ....... 22 5,663 966 5.7% 3,971 2.3%
West Texas / New
Mexico ......... 468 2,820 938 5.5% 7,722 4.4%
Louisiana ........ 68 233 107 0.6% 1,152 0.7%
Other ............ 44 1,298 261 1.6% 2,718 1.5%
-------- -------- -------- ------- -------- -------
Total ...... 11,904 30,141 16,928 100.0% $176,500 100.0%
======== ======== ======== ======= ======== =======
The estimates as of December 31, 1999 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 October
1999 for properties representing 86% of the estimated present value of the
Company's proved developed producing reserves and through earlier dates for the
balance of the Company's properties. In order to calculate the proved reserve
estimates as of December 31, 1999, 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 Securities and Exchange
Commission (the "Commission"), the estimates of the Company's proved reserves
and future net revenues therefrom set forth
8
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
increased substantially from December 31, 1998 to December 31, 1999, resulting
in significant increases in the Company's estimated future net revenues and
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, 1999 were $25.09 per Bbl of oil and $2.36
per Mcf of gas, as compared to $10.33 per Bbl and $1.77 per Mcf as of December
31, 1998. Both oil and gas prices have increased significantly since December
31, 1999.
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 Engineer's 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 20% of the Company's total proved reserves at December 31,
1999 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, 1999 assumes, based on the Company's estimates, that aggregate
capital expenditures by the Company of approximately $19.3 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 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.
9
Since January 1, 1999, 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,
----------------------------------------------------
1999 1998 1997
--------------- ---------------- ---------------
Gross Net Gross Net Gross Net
Development Wells:
Oil ............... 3 2.4 10 6.6 33 28.0
Gas ............... 1 .3 -- -- 1 .2
Dry ............... 1 .5 -- -- -- --
----- ----- ----- ------ ----- ------
Total ........... 5 3.2 10 6.6 34 28.2
===== ===== ===== ====== ===== ======
Exploratory Wells:
Oil ............... 1 .6 2 .8 8 7.5
Gas ............... 2 2.0 4 2.2 -- --
Dry ............... 3 1.1 10 6.6 5 1.9
----- ----- ----- ------ ----- ------
Total ........... 6 3.7 16 9.6 13 9.4
===== ===== ===== ====== ===== ======
Total Wells:
Oil ............... 4 3.0 12 7.4 41 35.5
Gas ............... 3 2.3 4 2.2 1 .2
Dry ............... 4 1.6 10 6.6 5 1.9
----- ----- ----- ------ ----- ------
Total ........... 11 6.9 26 16.2 47 37.6
===== ===== ===== ====== ===== ======
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, 1999, of productive wells in the areas indicated.
Oil Gas Total
----------------- ---------------- -----------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Trend ............. 292 225.7 22 15.2 314 240.9
West Texas / New
Mexico .......... 24 12.9 11 1.2 35 14.1
Louisiana ......... 2 1.2 3 .8 5 2.0
East Texas ........ -- -- 108 10.7 108 10.7
Cotton Valley ..... -- -- 2 2.0 2 2.0
Other ............. 8 6.3 24 7.4 32 13.7
----- ------- ----- ------ ----- -------
Total ........ 326 246.1 170 37.3 496 283.4
===== ======= ===== ====== ===== =======
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,
1999, the Company was the operator of 390 wells, or approximately 79% of the 496
total wells in which it has a working interest. Production from these operated
wells represented approximately 91% of the Company's total net production for
1999.
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,
---------------------------------
1999 1998 1997
------- ------- -------
Oil and Gas Production Data :
Oil (MBbls) ........................... 1,876 2,528 2,903
Gas (MMcf) ............................ 4,847 4,833 5,091
Total (MBOE) .......................... 2,684 3,334 3,752
Average Oil and Gas Sales Price (1):
Oil ($/Bbl) ........................... $ 17.44 $ 16.20 $ 19.80
Gas ($/Mcf)(2) ........................ $ 2.34 $ 2.35 $ 2.64
Average Production Costs
Lease operations ($/BOE)(3) ........... $ 4.18 $ 4.27 $ 4.32
- ----------
(1) Includes effects of hedging transactions.
(2) Includes natural gas liquids.
(3) Includes direct lifting costs (labor, repairs and maintenance, materials
and supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.
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,
---------------------------------
1999 1998 1997
------- ------- -------
(In thousands)
Property Acquisitions:
Proved .......................... $ -- $ 7,077 $ --
Unproved ........................ 3,221 10,602 14,042
Developmental Costs ............... 8,199 7,285 32,656
Exploratory Costs ................. 6,912 22,319 13,813
------- ------- -------
Total ........................... $18,332 $47,283 $60,511
======= ======= =======
Acreage
The following table sets forth certain information regarding the Company's
developed and undeveloped leasehold acreage as of December 31, 1999 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 / Cotton Valley . 114,848 104,133 81,235 60,967 196,083 165,100
Louisiana ............. 868 729 49,774 21,796 50,642 22,525
West Texas / New Mexico 2,005 1,259 10,676 2,479 12,681 3,738
East Texas ............ 2,477 1,665 -- -- 2,477 1,665
Other (1) ............. 13,013 6,510 267,259 136,706 280,272 143,216
------- ------- ------- ------- ------- -------
Total ............ 133,211 114,296 408,944 221,948 542,155 336,244
======= ======= ======= ======= ======= =======
(1) Net undeveloped acres are attributable to the following areas: the Glen
Rose area in Southeast Texas - 71,435; Colorado - 18,684; Mississippi -
13,739; Alabama - 13,486; Wyoming - 8,515; South Texas - 8,325, and other
- 2,522.
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, 1999.
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, 1999, there were
approximately 1,200 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, 1999:
Fourth Quarter ................. $ 16 1/4 $ 9 13/16
Third Quarter .................. 14 1/4 5 3/8
Second Quarter ................. 6 15/16 4 1/16
First Quarter .................. 11 1/4 2 11/16
Year Ended December 31, 1998:
Fourth Quarter ................. $ 10 1/2 $ 6 1/2
Third Quarter .................. 11 3/4 5 5/16
The quotations in the table above reflect inter-dealer prices without
retail markups, markdowns or commissions. On March 22, 2000, the last reported
sale price for the Common Stock on the Nasdaq Stock Market's National Market was
$14.50.
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,
1999 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,
--------------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
Statement of Operations Data: (In thousands, except per share data)
Revenues:
Oil and gas sales ...................... $ 44,366 $ 51,932 $ 70,929 $ 60,610 $ 43,883
Natural gas services ................... 3,684 3,795 4,559 4,281 5,388
-------- -------- -------- -------- --------
Total revenues .................... 48,050 55,727 75,488 64,891 49,271
-------- -------- -------- -------- --------
Costs and expenses:
Lease operations ....................... 11,222 14,237 16,205 14,776 13,533
Exploration:
Abandonments and impairments ...... 5,245 16,128 2,692 597 1,472
Seismic and other ................. 1,418 4,501 7,629 1,036 83
Natural gas services ................... 3,098 3,242 3,955 3,437 3,714
Depreciation, depletion and amortization 20,810 31,665 31,273 23,758 25,110
Impairment of property and equipment (1) 81 8,493 236 1,186 10,259
General and administrative ............. 3,929 4,299 4,181 3,266 3,708
-------- -------- -------- -------- --------
Total costs and expenses .......... 45,803 82,565 66,171 48,056 57,879
-------- -------- -------- -------- --------
Operating income (loss) ........... 2,247 (26,838) 9,317 16,835 (8,608)
-------- -------- -------- -------- --------
Other income (expense):
Interest expense ....................... (2,893) (2,384) (1,767) (3,440) (5,493)
Gain on sales of property and equipment 10,926 53 155 293 5,978
Other income ........................... 474 85 62 42 44
-------- -------- -------- -------- --------
Total other income (expense) ...... 8,507 (2,246) (1,550) (3,105) 529
-------- -------- -------- -------- --------
Income (loss) before income taxes ........... 10,754 (29,084) 7,767 13,730 (8,079)
Income tax expense .......................... -- -- -- -- --
-------- -------- -------- -------- --------
Net income (loss) ........................... $ 10,754 $(29,084) $ 7,767 $ 13,730 $ (8,079)
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic .................................. $ 1.19 $ (3.27) $ .87 $ 1.80 $ (1.31)
======== ======== ======== ======== ========
Diluted ................................ $ 1.18 $ (3.27) $ .85 $ 1.76 $ (1.31)
======== ======== ======== ======== ========
Weighted average common shares outstanding:
Basic .................................. 9,005 8,905 8,888 7,624 6,165
======== ======== ======== ======== ========
Diluted ................................ 9,148 8,905 9,094 7,800 6,165
======== ======== ======== ======== ========
Other Data:
Net cash provided by operating activities ... 24,738 $ 33,505 $ 39,324 $ 40,306 $ 24,203
EBITDAX (2) ................................. 29,801 $ 33,949 $ 51,147 $ 43,412 $ 28,316
December 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
(In thousands)
Balance Sheet Data:
Working capital (deficit) .......................................... $ (6,649) $ (15,848) $ (6,369)
Total assets ....................................................... 109,166 120,653 134,562
Long-term debt ..................................................... 30,500 39,100 35,700
Stockholders' equity ............................................... 56,117 44,394 73,074
- ----------
(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) 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, 1999, and
results of operations and cash flows for each of the three years in the period
ended December 31, 1999. 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
A significant portion of the Company's proved oil and gas reserves are
concentrated 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 needs to maintain or increase its
level of drilling activity and achieve comparable or improved results from such
activities. However, low oil prices caused the Company to temporarily suspend
Trend drilling activities from April 1998 through September 1999, resulting in
significant declines in oil production from 1997 levels.
Since 1997, the Company has initiated several exploratory projects
designed to reduce its dependence on Trend drilling for future production and
reserve growth. These new areas include the Company's Cotton Valley Pinnacle
Reef exploratory project, which targets deep gas structures in the vicinity of
its core properties in east central Texas, as well as other exploratory projects
in south Texas, Louisiana and Mississippi, and emphasize the development of
long-life gas reserves. During 1999, the Company devoted a substantial portion
of its capital expenditures to these new areas. In the aggregate, exploratory
drilling activities accounted for about 32% of the Company's 4,790 MBOE of
proved reserves added through extensions and discoveries during 1999.
The Company 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,
------------------------------
1999 1998 1997
-------- -------- --------
Oil and Gas Production Data:
Oil (MBbls) .............................. 1,876 2,528 2,903
Gas (MMcf) ............................... 4,847 4,833 5,091
Total (MBOE) (1) ......................... 2,684 3,334 3,752
Average Oil and Gas Sales Prices (2):
Oil ($/Bbl) .............................. $ 17.44 $ 16.20 $ 19.80
Gas ($/Mcf) .............................. $ 2.34 $ 2.35 $ 2.64
Operating Costs and Expenses ($/BOE Produced):
Lease operations ......................... $ 4.18 $ 4.27 $ 4.32
Oil and gas depletion .................... $ 7.46 $ 9.24 $ 8.10
General and administrative ............... $ 1.46 $ 1.29 $ 1.11
Net Wells Drilled (3):
Exploratory Wells ........................ 3.7 9.6 9.4
Developmental Wells ...................... 3.2 6.6 28.2
- ----------
(1) Gas is converted to barrel of oil equivalents (BOE) at the ratio of six
Mcf of gas to one Bbl of oil.
(2) Includes effects of hedging transactions.
(3) Excludes wells being drilled or completed at the end of each period.
1999 Compared to 1998
Revenues
Oil and gas sales decreased 14% from $51.9 million in 1998 to $44.4
million in 1999 due primarily to a 26% decline in oil production, offset in part
by an 8% increase in the Company's average oil price (net of hedging
transactions). The decline in oil production was caused primarily by the
suspension of Trend drilling activities from April 1998 through September 1999
in response to low oil prices. Gas production from new wells, primarily
attributable to the Cotton Valley Pinnacle Reef area, was offset by the loss of
production from two gas properties sold in 1999.
The Company's average price per barrel of oil increased 8% after giving
effect to an $.11 per barrel loss on hedging activities in 1999 as compared to a
$3.50 per barrel gain in 1998. Average gas prices were consistent after giving
effect to a $.02 per Mcf hedging loss in 1999 as compared to a $.23 Mcf gain in
1998.
Costs and Expenses
Lease operations expenses decreased 21% from $14.2 million in 1998 to
$11.2 million in 1999 due primarily to a combination of cost reduction measures
implemented by the Company, beginning in the fourth quarter of 1998, and lower
costs attributable to the sale of two gas properties in 1999. Oil and gas
production on a BOE basis decreased 19% during the current period, causing a 2%
decrease in lease operations expenses on a BOE basis from $4.27 per BOE in 1998
to $4.18 per BOE in 1999.
Exploration costs decreased from $20.6 million in 1998 to $6.7 million in
1999 due primarily to the charge-off during the 1998 period of 10 gross (6.6
net) exploratory dry holes totaling $7.7 million and $8.4 million of unproved
property impairments, as compared to only 3 gross (1.1 net) exploratory dry
holes totaling
17
$1.2 million and $4 million of unproved property impairments during 1999.
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 decreased 34%
from $31.7 million in 1998 to $20.8 million in 1999 due primarily to a 19%
decrease in the Company's average depletion rate per BOE. The lower depletion
rate was attributable to the effects of higher oil and gas prices on estimated
quantities of proved reserves combined with a 19% 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 $7.46
in 1999 compared to $9.24 in 1998.
General and administrative ("G&A") expenses decreased 9% from $4.3 million
in 1998 to $3.9 million in 1999 due primarily to certain cost reduction measures
initiated in December 1998. These cost reduction measures, consisting primarily
of personnel layoffs and salary reductions, were originally expected to achieve
a 33% annual savings. However, many of these measures were reversed during the
last half of 1999 due to an increase in drilling activity prompted by higher
product prices.
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 an $81,000 provision in 1999.
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, while the 1999
provision related to a minor value property.
Interest Expense and Other
Interest expense increased 21% from $2.4 million in 1998 to $2.9 million
in 1999 due primarily to a combination of lower capitalized interest and higher
average levels of indebtedness on the Company's secured bank credit facility
(the "Credit Facility"). The average daily principal balance outstanding on such
facility during 1999 was $42 million compared to $40.8 million in 1998. The
effective annual interest rate on bank debt, including bank fees, during the
1999 and 1998 periods was 8.1%. Capitalized interest was $420,000 less during
the 1999 period due to a decrease in unproved acreage.
Gain on sales of property and equipment increased from $53,000 in 1998 to
$10.9 million in 1999. The 1999 gain resulted primarily from the sale of the
Company's interests in eight non-operated oil and gas wells located in Matagorda
County, Texas, and its interests in the Jalmat Field located in Lea County, New
Mexico.
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
18
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.
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.
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.
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 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.
19
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 2000, and the expected capital resources needed to
finance such plans.
Capital Expenditures
The Company plans to spend $43 million on exploration and development
activities during 2000, including $11.8 million in the Trend, $12 million on the
Cotton Valley Exploratory Project, $9.8 million on various exploratory prospects
in Louisiana and $9.4 million on other projects. See "Business - Drilling,
Exploration and Production Activities."
The Company may increase or decrease its planned activities for 2000,
depending upon drilling results, product prices, the availability of capital
resources, and other factors affecting the economic viability of such
activities.
Capital Resources
Credit Facility
The Credit Facility provides for a revolving loan facility in an amount
not to exceed the lesser of the borrowing base, as established by the banks, or
that portion of the borrowing base determined by the Company to be the elected
borrowing limit. At December 31, 1999, the borrowing base was $48 million and
the outstanding advances were $30.5 million. The borrowing base is subject to
redetermination at any time, but at least semi-annually, and is made at the
discretion of the banks. If the redetermined borrowing base is less than the
amount of outstanding indebtedness, the Company will be required to (i) pledge
additional collateral, (ii) prepay the excess in not more than five equal
monthly installments, or (iii) elect to convert the entire amount of outstanding
indebtedness to a term obligation based on amortization formulas set forth in
the loan agreement.
Working Capital and Cash Flow
During 1999, the Company generated cash flow from operating activities of
$24.7 million, received $19.1 million in proceeds from the sale of property and
equipment, repaid $24.4 million of indebtedness on the Credit Facility and spent
$19.7 million on capital expenditures.
The Company's working capital deficit decreased from $15.8 million at
December 31, 1998 to $6.6 million at December 31, 1999. 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. In November 1999, the banks redetermined the borrowing
base and did not require any mandatory principal
20
repayments. The Company also reported $7.5 million of net book values on
properties held for resale as current assets as of December 31, 1998, while no
properties were classified as current assets as of December 31, 1999.
The Company believes that the funds available under the Credit Facility
and cash provided by operations will be adequate to fund the Company's
operations and projected capital and exploratory expenditures during 2000.
However, because future cash flows and the availability of borrowings under the
Credit Facility are subject to a number of variables, such as prevailing prices
of oil and gas, actual production from existing and newly-completed wells, the
Company's success in developing and producing new reserves, and the uncertainty
with respect to the amount of funds which may ultimately be required to 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.
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 1999.
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 have been able to properly recognize dates in the
year 2000. This could have resulted 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 developed a "Year 2000 Plan" in 1998 and
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 was comprised of various phases, including assessment,
remediation, testing and contingency plan development.
By early 1999, the Company's inventory of computer hardware and software
was substantially Year 2000 compliant. The programming modifications for the oil
and gas accounting and production systems were completed by the software vendor
in 1997 and were installed and tested by the Company in November 1998. The
Company also uses monitor and control equipment with embedded chip technology in
its 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.
In 1999, the Company also began 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 would not be adversely affected by the Year 2000 compliance problems
of others.
The Company has experienced no computer systems or equipment failures
related to the arrival of the Year 2000. All systems and equipment have
continued to be operational, and the Company has no reason to believe that any
of its systems and equipment are not Year 2000 compliant. Furthermore, the
Company is not aware of any Year 2000 compliance problems of Third Party
Providers which have adversely affected, or which may in the future adversely
affect, the Company's ability to conduct business with such Third Party
Providers.
21
The costs to implement the Year 2000 Plan were nominal since the primary area
for remediation involved software covered by a maintenance agreement. The
Company believes that the Year 2000 Plan has been successfully completed and,
except for routine monitoring of its computer systems and equipment, does not
plan to take any further action in regards to Year 2000 issues.
Item 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, 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 1999 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
$2.4 million.
During 1998 and continuing into 1999, the oil and gas industry operated in
a depressed commodity price environment. Oil prices during the first quarter of
1999 fell to their lowest levels in history when adjusted for inflation. Since
then, oil prices have steadily improved, and in March 2000, peaked at over $34
per barrel on the NYMEX. Gas prices have also improved since March 1999, but
like the oil markets, remain very volatile.
From time to time, the Company has utilized hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure to
price fluctuations. While the use of these hedging arrangements limits the
downside risk of price declines, such use may also limit any benefits which may
be derived from price increases. The Company uses various financial instruments,
such as swaps and collars, whereby monthly settlements are based on differences
between the prices specified in the instruments and the settlement prices of
certain futures contracts quoted on the NYMEX or certain other indices.
Generally, when the applicable settlement price is less than the price specified
in the contract, the 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
22
utilized by the Company differ from futures contracts in that there is not a
contractual obligation which requires or permits the future physical delivery of
the hedged products.
Except for a floor of $10.00 per barrel on 800,000 barrels of oil
production from January 1999 through June 1999, the Company did not have any
significant hedging arrangements in place for 1999. However, in January 2000,
the Company entered into swap arrangements covering 1,830,000 MMBtu of its gas
production from February 2000 through May 2000 at an average price of $2.26 per
MMBtu. This position was subsequently terminated at an aggregate loss of
approximately $800,000.
Also in February 2000, the Company entered into swap arrangements covering
740,000 barrels of its oil production from July 2000 through December 2000 and
from April 2001 through October 2001 at an average price of $22.49 per barrel
(ranging from a high of $25.00 per barrel in July 2000 to a low of $20.03 in
October 2001), and entered into a collar arrangement covering 170,000 barrels of
its oil production from January 2001 through March 2001 at an average floor
price of $20.66 per barrel and an average ceiling price of $23.81 per barrel.
Interest Rates
All of the Company's outstanding indebtedness at December 31, 1999 is
subject to market rates of interest as determined from time to time by the banks
pursuant to the Credit Facility. See "Capital Resources". The Company may
designate borrowings under the Credit Facility as either "Base Rate Loans" or
"Eurodollar Loans." Base Rate Loans bear interest at a fluctuating rate that is
linked to the discount rates established by the Federal Reserve Board.
Eurodollar Loans bear interest at a fluctuating rate that is linked to LIBOR.
Any increases in these interest rates can have an adverse impact on the
Company's results of operations and cash flow. Although various financial
instruments are available to hedge the effects of changes in interest rates, the
Company does not consider the risk to be significant and has not entered into
any interest rate hedging transactions. Based on the Company's outstanding
indebtedness at December 31, 1999 of $30.5 million, a change in interest rates
of 25 basis points would affect future annual interest payments by approximately
$76,000.
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.
23
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, 1999.
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, 1999.
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, 1999.
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, 1999.
24
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,
1999.
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 Seventh Restated Loan Agreement dated as of December 1, 1999,
among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI
Acquisitions, Inc., Bank One, Texas, N.A. and Union Bank of
California, N.A.
**10.2 1993 Stock Compensation Plan, filed as an exhibit to the Form S-8
Registration Statement, Registration No. 33-68318
**10.3 First Amendment to 1993 Stock Compensation Plan, filed as an
exhibit to the December 31, 1995 Form 10-K
**10.4 Second Amendment to the 1993 Stock Compensation Plan, filed as an
exhibit to the Form S-8 Registration Statement, Registration No.
33-68318
**10.5 Outside Directors Stock Option Plan, filed as an exhibit to the
Form S-8 Registration Statement, Registration No. 33-68316
**10.6 First Amendment to Outside Directors Stock Option Plan, filed as
an exhibit to the December 31, 1995 Form 10-K
**10.7 Bonus Incentive Plan, filed as an exhibit to the Form S-8
Registration Statement, Registration No. 33-68320
**10.8 First Amendment to Bonus Incentive Plan, filed as an exhibit to
the December 31, 1997 Form 10-K
**10.9 Amended and Restated 401(k) Plan & Trust, filed as an exhibit to
the December 31, 1995 Form 10-K
**10.10 Second Amendment to Amended and Restated 401(k) Plan & Trust,
filed as an exhibit to the December 31, 1995 Form 10-K
25
Exhibit
Number Description of Exhibit
- ---------- ------------------------------------------------------------------
**10.11 Third Amendment to Amended and Restated 401(k) Plan & Trust, filed
as an exhibit to the December 31, 1995 Form 10-K
**10.12 Executive Incentive Stock Compensation Plan, filed as an exhibit
to the Form S-8 Registration Statement, Registration No. 33-92834
**10.13 First Amendment to Executive Incentive Stock Compensation Plan,
filed as an exhibit to the December 31, 1996 Form 10-K
**10.14 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
**10.15 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
**10.16 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 Schedule for the year ended December 31, 1999
- ----------
* Filed herewith
** Incorporated by reference to the filing indicated
26
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 *
--------------------------------------
Clayton W. Williams
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 * Chairman of the Board, March 28, 2000
- ------------------------------ President and Chief Executive
Clayton W. Williams Officer and Director
/s/ L. PAUL LATHAM Executive Vice President, March 28, 2000
- ------------------------------ Chief Operating Officer and
L. Paul Latham Director
/s/ MEL G. RIGGS * Senior Vice President - March 28, 2000
- ------------------------------ Finance, Secretary, Treasurer,
Mel G. Riggs Chief Financial Officer and
Director
/s/ JERRY F. GRONER * Vice President - Land and March 28, 2000
- ------------------------------ Lease Administration and
Jerry F. Groner Director
/s/ STANLEY S. BEARD * Director March 28, 2000
- ------------------------------
Stanley S. Beard
/s/ WILLIAM P. CLEMENTS * Director March 28, 2000
- ------------------------------
William P. Clements
/s/ ROBERT L. PARKER * Director March 28, 2000
- ------------------------------
Robert L. Parker
* By: /s/ L. PAUL LATHAM
----------------------------
L. Paul Latham
Attorney-in-Fact
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. (a Delaware corporation) as of December 31, 1999 and 1998,
and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the three years in the period ended December 31, 1999.
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 auditing standards generally
accepted in the United States. 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, 1999 and 1998, and the results of its operations and
cash flows for each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
February 25, 2000
F-2
CLAYTON WILLIAMS ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
ASSETS
December 31,
----------------------
1999 1998
CURRENT ASSETS
Cash and cash equivalents ....................................... $ 1,634 $ 1,424
Accounts receivable:
Trade, net ................................................. 2,661 6,782
Affiliates ................................................. 729 244
Oil and gas sales .......................................... 9,846 3,628
Inventory ....................................................... 717 1,230
Property held for resale ........................................ -- 7,521
Other ........................................................... 313 482
--------- ---------
15,900 21,311
--------- ---------
PROPERTY AND EQUIPMENT
Oil and gas properties, successful efforts method ............... 436,831 424,360
Natural gas gathering and processing systems .................... 9,810 8,292
Other ........................................................... 10,350 10,480
--------- ---------
456,991 443,132
Less accumulated depreciation, depletion and amortization ....... (363,985) (343,857)
--------- ---------
Property and equipment, net ................................ 93,006 99,275
--------- ---------
OTHER ASSETS .......................................................... 260 67
--------- ---------
$ 109,166 $ 120,653
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable:
Trade ...................................................... $ 13,648 $ 16,384
Affiliates ................................................. 310 65
Oil and gas sales .......................................... 7,785 3,433
Current maturities of long-term debt ............................ -- 15,800
Accrued liabilities and other ................................... 806 1,477
--------- ---------
22,549 37,159
--------- ---------
LONG-TERM DEBT ........................................................ 30,500 39,100
--------- ---------
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 - 9,167,779 shares in 1999 and
8,937,561 shares in 1998 ....................................... 917 894
Additional paid-in capital ...................................... 70,690 69,744
Retained deficit ................................................ (15,490) (26,244)
--------- ---------
56,117 44,394
--------- ---------
$ 109,166 $ 120,653
========= =========
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,
--------------------------------
1999 1998 1997
-------- -------- --------
REVENUES
Oil and gas sales ...................... $ 44,366 $ 51,932 $ 70,929
Natural gas services ................... 3,684 3,795 4,559
-------- -------- --------
Total revenues .................... 48,050 55,727 75,488
-------- -------- --------
COSTS AND EXPENSES
Lease operations ....................... 11,222 14,237 16,205
Exploration:
Abandonments and impairments ...... 5,245 16,128 2,692
Seismic and other ................. 1,418 4,501 7,629
Natural gas services ................... 3,098 3,242 3,955
Depreciation, depletion and amortization 20,810 31,665 31,273
Impairment of property and equipment ... 81 8,493 236
General and administrative ............. 3,929 4,299 4,181
-------- -------- --------
Total costs and expenses .......... 45,803 82,565 66,171
-------- -------- --------
Operating income (loss) ........... 2,247 (26,838) 9,317
-------- -------- --------
OTHER INCOME (EXPENSE)
Interest expense ....................... (2,893) (2,384) (1,767)
Gain on sales of property and equipment 10,926 53 155
Other .................................. 474 85 62
-------- -------- --------
Total other income (expense) ...... 8,507 (2,246) (1,550)
-------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES ............ 10,754 (29,084) 7,767
-------- -------- --------
INCOME TAX EXPENSE
Current ................................ -- -- --
Deferred ............................... -- -- --
-------- -------- --------
Total income tax expense .......... -- -- --
-------- -------- --------
NET INCOME (LOSS) ............................ $ 10,754 $(29,084) $ 7,767
======== ======== ========
Net income (loss) per common share:
Basic .................................. $ 1.19 $ (3.27) $ .87
======== ======== ========
Diluted ................................ $ 1.18 $ (3.27) $ .85
======== ======== ========
Weighted average common shares outstanding:
Basic .................................. 9,005 8,905 8,888
======== ======== ========
Diluted ................................ 9,148 8,905 9,094
======== ======== ========
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, 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
Issuance of stock through
compensation plans .......... 230 23 946 -- 969
Net income ................... -- -- -- 10,754 -- 10,754
------- -------- -------- -------- -------- --------
BALANCE,
December 31, 1999 ................. 9,168 $ 917 $ 70,690 $(15,490) $ -- $ 56,117
======= ======== ======== ======== ======== ========
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,
--------------------------------
1999 1998 1997
-------- -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) ................................. $ 10,754 $(29,084) $ 7,767
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation, depletion and amortization ..... 20,810 31,665 31,273
Impairment of property and equipment ......... 81 8,493 236
Exploration costs ............................ 5,245 16,128 2,692
Gain on sales of property and equipment ...... (10,926) (53) (155)
Other ........................................ 274 375 582
Changes in operating working capital:
Accounts receivable .......................... (2,582) 2,842 (1,088)
Accounts payable ............................. 1,064 1,448 766
Other ........................................ 18 1,691 (2,749)
-------- -------- --------
Net cash provided by operating activities 24,738 33,505 39,324
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment ............... (19,683) (53,720) (56,167)
Proceeds from sales of property and equipment ..... 19,060 260 303
Other ............................................. (200) -- --
-------- -------- --------
Net cash used in investing activities ... (823) (53,460) (55,864)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt ...................... -- 19,200 17,700
Repayments of long-term debt ...................... (24,400) -- --
Repurchase of common stock for treasury ........... -- -- (1,520)
Proceeds from sale of common stock ................ 695 29 31
-------- -------- --------
Net cash provided by (used in) financing
activities ............................ (23,705) 19,229 16,211
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS ....................................... 210 (726) (329)
CASH AND CASH EQUIVALENTS
Beginning of period ............................... 1,424 2,150 2,479
-------- -------- --------
End of period ..................................... $ 1,634 $ 1,424 $ 2,150
======== ======== ========
SUPPLEMENTAL DISCLOSURES
Cash paid for interest, net of amounts
capitalized ..................................... $ 3,021 $ 2,291 $ 1,668
======== ======== ========
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. (a Delaware corporation) and its
subsidiaries (collectively, the "Company") is an independent oil and gas company
engaged in the exploration for and development and production of oil and natural
gas primarily in Texas, Louisiana and New Mexico.
Substantially all of the Company's oil and gas production is sold under
short-term contracts which are market-sensitive. Accordingly, the Company's
financial condition, results of operations, and capital resources are highly
dependent upon prevailing market prices of, and demand for, oil and natural gas.
These commodity prices are subject to wide fluctuations and market uncertainties
due to a variety of factors that are beyond the control of the Company. These
factors include the level of global demand for petroleum products, foreign
supply of oil and gas, the establishment of and compliance with production
quotas by oil-exporting countries, weather conditions, the price and
availability of alternative fuels, and overall economic conditions, both foreign
and domestic. From time to time, the Company utilizes hedging transactions with
respect to a portion of its oil and gas production to mitigate its exposure to
price fluctuations (see Note 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 materially 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. Proceeds from
sales of properties are credited to property costs, and a gain or loss is
recognized when a significant portion of an amortization base is sold or
abandoned.
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. The acquisition costs of unproved acreage are initially
capitalized and are carried at cost, net of accumulated impairment provisions,
until such leases are transferred to proved properties or charged to exploration
expense as impairments of unproved properties.
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
F-7
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 based upon prices at which management reasonably
estimates such products will be sold. These estimates of future product prices
may differ from current market prices of oil and gas. Any downward revisions to
management's estimates of product prices could result in an impairment of the
Company's oil and gas properties in future periods.
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.
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, 1999, 1998 and 1997, the Company capitalized interest totaling approximately
$547,000, $967,000 and $346,000, 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 per
share gives further effect to the additional dilution, if any, related to
outstanding employee stock options. In periods when a net loss is reported,
diluted loss per share is the same as basic loss per share since the effects of
outstanding employee stock options are 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, 1999,
1998 or 1997.
Investments in Equity Securities
The Company accounts for investments in equity securities as "available
for sale" investments under Statement of Financial Accounting Standards No. 115
"Accounting for Certain Investments in Debt and Equity Securities." As of
December 31, 1999, the Company held equity securities in a corporation which
operates an internet marketplace for petroleum services and equipment. The
investment is carried at its cost of $200,000, which management believes
approximates its fair market value, and is classified as a non-current other
asset in the accompanying balance sheet at December 31, 1999.
Comprehensive Income
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, 1999, 1998 and 1997, the Company reported no differences between
comprehensive income and net income.
Reclassifications
Certain reclassifications of prior year financial statement amounts have
been made to conform to current year presentations.
3. Long-Term Debt
Long-term debt consists of the following:
December 31,
-----------------
1999 1998
------- -------
(In thousands)
Secured Bank Credit Facility (matures July 31, 2001) $30,500 $54,900
Less current maturities ............................ -- 15,800
------- -------
$30,500 $39,100
======= =======
Aggregate maturities of long-term debt at December 31, 1999 are as
follows: 2000 - $0; and 2001 - $30,500,000.
F-9
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1999, the
borrowing base was $48 million and the outstanding advances were $30.5 million.
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 determined at the discretion of the banks. If
the redetermined borrowing base is less than the amount of outstanding
indebtedness, the Company will be required to (i) pledge additional collateral,
(ii) prepay the excess in not more than five equal monthly installments, or
(iii) elect to convert the entire amount of outstanding indebtedness to a term
obligation based on amortization formulas set forth in the loan agreement.
Substantially all of the Company's oil and gas properties are pledged to secure
advances under 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. At December 31, 1999, the Company's indebtedness under the credit
facility consisted of $20 million of Eurodollar Loans at a rate of 8.7% and
$10.5 million of Base Rate Loans at a rate of 8.8%. The book value of
outstanding advances under the credit facility approximates its estimated fair
market value.
In addition, the Company pays the banks a commitment fee equal to 1/4% per
annum on the unused portion of the revolving loan commitment. Interest on the
revolving loan and commitment fees are payable quarterly, and all outstanding
principal and interest will be due July 31, 2001.
The loan agreement contains financial covenants that are computed
quarterly and require the Company to maintain minimum levels of working capital,
cash flow and net tangible assets. The Company was in compliance with all of the
financial covenants at December 31, 1999. In addition, the Company is required
to comply with other non-financial covenants contained in the loan agreement. At
the request of the Company, the banks agreed to modify a certain non-financial
covenant to permit the Company to invest $200,000 in the equity securities of a
corporation which operates an internet marketplace for petroleum services and
equipment.
4. Property Held for Resale
At December 31, 1998, the Company had identified two properties for sale
in 1999. The net book value of these properties aggregated $7.5 million and was
classified as a current asset in the accompanying consolidated balance sheet at
December 31, 1998. 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 April 1999, the Company sold its interests in the
Jalmat Field located in Lea County, New Mexico for $12.5 million. Proceeds from
these sales were used to reduce indebtedness on the secured bank credit
facility. The Company reported a net gain of $10.2 million from the sale of
these two properties in 1999.
5. Stockholders' Equity
In January 1997, the Company repurchased 95,000 shares of its common stock
on the open market at a cost of $1,520,000. These shares were classified as
treasury stock until they were cancelled in June 1998. The cost of the cancelled
shares was reclassified as a reduction in common stock and additional paid-in
capital.
F-10
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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. 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, 1999 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 1999, 1998 and
1997.
1999 1998 1997
------------------------ ----------------------- ----------------------
Weighted Weighted Weighted
Average Average Average
Shares Price Shares Price Shares Price
--------- ----------- -------- ----------- --------- ---------
Beginning of year . 722,052 $ 11.23 632,269 $ 10.99 458,766 $ 8.46
Granted (a) . 304,870 $ 5.50 110,168 $ 11.61 210,700 $ 15.36
Exercised ... (188,200) $ 3.55 (12,305) $ 2.39 (12,791) $ 2.53
Forfeited ... (18,668) $ 10.85 (8,080) $ 11.69 (24,406) $ 5.53
Cancelled (b) (293,889) $ 14.15 -- -- -- --
--------- -------- ---------
End of year ....... 526,165 $ 9.03 722,052 $ 11.23 632,269 $ 10.99
========= ======== =========
Exercisable ....... 254,204 $ 11.02 261,089 $ 7.72 194,357 $ 6.00
========= =========== ======== =========== ========= =========
Issuable .......... 148,329 140,642 242,730
========= ======== =========
- ----------
(a) In addition to the reissuances described in Note (b), the Company granted
new options as follows: 1999 - 9,981 shares at $5.50 per share and 1,000
shares at $6.00 per share; 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; and
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.
(b) In 1999, the Company exchanged options to purchase 293,889 shares, which
were originally granted in 1997 and 1998 at a weighted average price of
$14.15 per share, for an equal number of options at a price of $5.50 per
share.
In November 1999, certain employees of the Company, including one officer,
borrowed an aggregate of $834,000 from a bank in order to finance the exercise
of stock options granted under the 1993 Plan. The Company guaranteed the loans,
and accordingly, was contingently liable for the full amount of such loans at
December 31, 1999.
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 21,000 shares of
common stock (3,000 per year from 1993 through 1999) 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
F-11
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
exercisable upon issuance. At December 31, 1999, options to purchase 17,000
shares were outstanding, and 65,300 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, 1999, 106,190 shares
remain available for issuance under this plan.
Stock Compensation Plans
The Company has a compensation plan which permits the Company to pay all
or part of selected executives' salaries in shares of common stock in lieu of
cash. The Company reserved an aggregate of 500,000 shares of common stock for
issuance under this plan. During 1999, 1998 and 1997, the Company issued 36,919,
28,789 and 30,808 shares, respectively, of common stock to one officer in lieu
of cash compensation aggregating $264,000, $278,000 and $421,000, respectively.
The amounts of such compensation are included in general and administrative
expense in the accompanying consolidated financial statements.
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:
1999 1998 1997
--------- ---------- ---------
(In thousands, except per share)
Net income (loss):
As reported .................. $ 10,754 $ (29,084) $ 7,767
Pro forma .................... 9,613 $ (30,172) $ 7,175
Net income (loss) per share:
Basic:
As reported ................ $ 1.19 $ (3.27) $ .87
Pro forma .................. $ 1.07 $ (3.39) $ .81
Diluted:
As reported ................ $ 1.18 $ (3.27) $ .85
Pro forma .................. $ 1.05 $ (3.39) $ .79
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
F-12
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
1999, 1998 and 1997, respectively: risk-free interest rates of 5.5%, 5.2% and
6.1%; dividend yields of 0%; volatility factors of the expected market price of
the Company's common stock of .74, .55 and .575; and a life expectancy of each
option of 7 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 $788,000, $664,000 and $684,000 for the
years ended December 31, 1999, 1998 and 1997, respectively, and include charges
to the Company by affiliates for rents and services aggregating $259,000,
$102,000 and $200,000 for the years ended December 31, 1999, 1998 and 1997,
respectively. The Company believes that all related party transactions are on
terms no less favorable than those available from unrelated third parties.
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 $408,000, $345,000 and $337,000 for the years ended December 31,
1999, 1998 and 1997, respectively.
Future minimum payments under noncancelable leases at December 31, 1999,
are as follows:
Operating
Leases
--------------
(In thousands)
2000 .......................................... $ 536
2001 .......................................... 475
2002 .......................................... 94
Thereafter .................................... 13
-------
Total minimum lease payments ............... $ 1,118
=======
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.
F-13
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 losses totaling $310,000 in 1999, net gains totaling
$9,871,000 in 1998 (comprised of gains of $10,024,000, partially offset by
losses of $153,000), and gains totaling $252,000 in 1997.
The Company did not have any open hedge positions as of December 31, 1999.
However, subsequent to December 31, 1999, the Company entered into certain
financial option arrangements, as follows:
- Swap arrangements covering 1,830,000 MMBtu of its gas production
from February 2000 through May 2000 at an average price of $2.26.
This position was subsequently terminated at an aggregate loss of
approximately $800,000.
- Swap arrangements covering 740,000 barrels of its oil production
from July 2000 through December 2000 and from April 2001 through
October 2001 at an average price of $22.49 (ranging from a high of
$25.00 per barrel in July 2000 to a low of $20.03 in October 2001).
- Collar arrangements covering 170,000 barrels of its oil production
from January 2001 through March 2001 at an average floor price of
$20.66 and an average ceiling price of $23.81.
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
The Company has recorded provisions for impairment under SFAS 121 of
$81,000, $8,493,000 and $236,000 for the years 1999, 1998 and 1997,
respectively. The 1998 provision was 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. The
provisions for 1999 and 1997 related to certain minor value properties.
The Company has also recorded provisions for impairment of unproved
properties aggregating $4 million, $8.4 million and $763,000 in 1999, 1998 and
1997, respectively, and have charged such impairments to exploration costs in
the accompanying statements of operations.
F-14
11. Purchases of Assets
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 $41.1 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 $15.5 million and has
recognized cumulative tax losses of approximately $37.1 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, 1999, 1998 and 1997.
The tax effected temporary differences and tax loss carryforwards which
comprise net deferred tax assets and liabilities are as follows:
December 31,
---------------------------------
1999 1998 1997
-------- -------- --------
(In thousands)
Deferred tax assets (liabilities):
Depreciable and depletable property .... $ (6,183) $ (2,394) $(12,828)
Tax loss carryforwards ................. 12,961 12,295 12,584
Other .................................. 956 970 936
Valuation allowance .................... (7,734) (10,871) (692)
-------- -------- --------
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 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and
reporting standards for derivative instruments and hedging activities. It
requires that derivatives be recognized as assets or liabilities and measured at
their fair value. SFAS 133 will be adopted in 2001 and is not expected to have a
material effect on the Company's financial condition or operations.
The Financial Accounting Standards Board has issued an exposure draft of
an interpretation to APB 25 which may adversely affect the Company's results of
operations in periods subsequent to its final issuance. The interpretation
requires certain stock options which the Company repriced in April 1999 to be
F-15
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
treated as compensatory. Accordingly, the Company will be required to recognize
compensation expense on such options to the extent that the quoted market value
of the Company's common stock in future periods exceeds its quoted market value
on the effective date of the final interpretation. Since the Company cannot
accurately predict the quoted market value at any future date, the Company
cannot presently quantify the level of compensation expense which may be
reported in future periods. However, any charge against earnings required
pursuant to the interpretation will be a non-cash expense and will not affect
cash flow from operating activities.
14. Quarterly Financial Data (Unaudited)
The following table summarizes results for each of the four quarters for
the years ended December 31, 1999 and 1998.
First Second Third Fourth
Quarter Quarter Quarter Quarter Year
-------- -------- -------- -------- --------
(In thousands, except per share)
Year ended December 31, 1999:
Total revenues ........................ $ 8,326 $ 10,780 $ 13,736 $ 15,208 $ 48,050
Gross profit (a) ...................... $ 4,961 $ 7,301 $ 9,981 $ 11,487 $ 33,730
Net income (loss) ..................... $ (185) $ 7,948 $ 1,896 $ 1,095 $ 10,754
Net income (loss) per common share (b):
Basic ............................ $ (.02) $ .89 $ .21 $ .12 $ 1.19
Diluted .......................... $ (.02) $ .87 $ .20 $ .12 $ 1.18
Year ended December 31, 1998:
Total revenues ........................ $ 17,765 $ 14,848 $ 12,384 $ 10,730 $ 55,727
Gross profit (a) ...................... $ 13,019 $ 10,233 $ 8,327 $ 6,669 $ 38,248
Net income (loss) ..................... $ 962 $ (6,196) $ (2,425) $(21,425) $(29,084)
Net income (loss) per common share (b):
Basic ............................ $ .11 $ .70 $ (.27) $ (2.40) $ (3.27)
Diluted .......................... $ .11 $ .70 $ (.27) $ (2.40) $ (3.27)
- ----------
(a) Gross profit is computed by the sum of oil and gas sales plus natural gas
services revenues less operating expenses. Operating expenses consist of
lease operations and costs associated with natural gas services.
(b) The sum of the individual quarterly net income (loss) per share amounts
may not agree to the total for the year due to each period's computation
based on the weighted average number of common shares outstanding during
each period.
15. 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,
---------------------------------
1999 1998 1997
------- ------- -------
(In thousands)
Property acquisitions:
Proved .................. $ -- $ 7,077 $ --
Unproved ................ 3,221 10,602 14,042
Developmental costs ............. 8,199 7,285 32,656
Exploratory costs ............... 6,912 22,319 13,813
------- ------- -------
Total ................... $18,332 $47,283 $60,511
======= ======= =======
F-16
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the capitalized costs for oil and gas
properties:
December 31,
-------------------------
1999 1998
--------- ---------
(In thousands)
Proved properties .............................. $ 431,311 $ 415,471
Unproved properties ............................ 5,520 8,889
--------- ---------
Total capitalized costs ........................ 436,831 424,360
Accumulated depreciation, depletion and
amortization ................................. (347,970) (328,231)
--------- ---------
Net capitalized costs .................. $ 88,861 $ 96,129
========= =========
16. 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.
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,
----------------------------------------------------------------------------------------------
1999 1998 1997
---------------------------- ---------------------------- ----------------------------
Oil Gas MBOE Oil Gas MBOE Oil Gas MBOE
------ ------ ------ ------ ------ ------ ------ ------ ------
Proved reserves
Beginning of period .......... 5,741 38,854 12,217 8,410 32,861 13,887 8,507 35,798 14,474
Revisions .................... 5,077 663 5,188 (744) (3,248) (1,285) (726) 1,020 (556)
Extensions and discoveries ... 3,239 9,306 4,790 254 8,768 1,716 3,532 1,134 3,721
Sales of minerals-in-place ... (277) (13,835) (2,583) -- -- -- -- -- --
Purchases of minerals-in-place -- -- -- 349 5,306 1,233 -- -- --
Production ................... (1,876) (4,847) (2,684) (2,528) (4,833) (3,334) (2,903) (5,091) (3,752)
------ ------ ------ ------ ------ ------ ------ ------ ------
End of period ................ 11,904 30,141 16,928 5,741 38,854 12,217 8,410 32,861 13,887
====== ====== ====== ====== ====== ====== ====== ====== ======
Proved developed reserves
Beginning of period .......... 5,504 32,215 10,873 7,826 27,392 12,392 7,199 30,496 12,282
====== ====== ====== ====== ====== ====== ====== ====== ======
End of period ................ 9,028 26,960 13,521 5,504 32,215 10,873 7,826 27,392 12,392
====== ====== ====== ====== ====== ====== ====== ====== ======
F-17
CLAYTON WILLIAMS ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The standardized measure of discounted future net cash flows relating to
proved reserves was as follows:
December 31,
------------------------------------
1999 1998 1997
--------- --------- ---------
(In thousands)
Future cash inflows .................................... $ 369,584 $ 128,149 $ 219,528
Future costs:
Production ..................................... (76,507) (43,647) (67,207)
Development .................................... (24,861) (9,999) (13,445)
Income taxes ................................... (56,959) -- (10,445)
--------- --------- ---------
Future net cash flows .................................. 211,257 74,503 128,431
10% discount factor .................................... (59,615) (22,442) (36,028)
--------- --------- ---------
Standardized measure of discounted future net cash flows $ 151,642 $ 52,061 $ 92,403
========= ========= =========
Changes in the standardized measure of discounted future net cash flows
relating to proved reserves were as follows:
Year Ended December 31,
-----------------------------------
1999 1998 1997
--------- --------- ---------
(In thousands)
Standardized measure, beginning of period .......... $ 52,061 $ 92,403 $ 135,713
Net changes in sales prices, net of production costs 63,593 (31,210) (49,024)
Revisions of quantity estimates .................... 58,821 (6,103) (4,376)
Accretion of discount .............................. 5,206 9,992 16,067
Changes in future development costs, including
development costs incurred that reduced future
development costs ................................. 1,850 8,415 8,622
Changes in timing and other ........................ (7,348) (2,758) (874)
Net change in income taxes ......................... (24,858) 7,515 17,442
Extensions and discoveries ......................... 46,892 7,165 23,557
Sales, net of production costs ..................... (33,144) (37,695) (54,724)
Sales of minerals-in-place ......................... (11,431) -- --
Purchases of minerals-in-place ..................... -- 4,337 --
--------- --------- ---------
Standardized measure, end of period ................ $ 151,642 $ 52,061 $ 92,403
========= ========= =========
F-18
INDEX TO EXHIBITS
Exhibit
Number Description of Exhibit
- ----------- ------------------------------------------------------------------
10.1 Seventh Restated Loan Agreement dated as of December 1, 1999,
among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI
Acquisitions, Inc., Bank One, Texas, N.A. 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, 1999