10-K405 1 a2042646z10-k405.txt 10-K405 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, 2000 / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from__________ to Commission File Number 0-20838 CLAYTON WILLIAMS ENERGY, INC. ------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) DELAWARE 75-2396863 -------------------------------- ------------------------------------- (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) SIX DESTA DRIVE - SUITE 6500 MIDLAND, TEXAS 79705-5510 -------------------------------- --------------------------------------- (Address of principal (Zip code) executive offices) Registrant's telephone number, including area code: (915) 682-6324 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock - $.10 Par Value ------------------------------------------------------------------------------- (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. [ X ] 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 20, 2001, 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 $81,274,440. There were 9,263,203 shares of Common Stock, $.10 par value, of the registrant outstanding as of March 20, 2001. 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, 2001. Such portions of the registrant's definitive Proxy Statement are incorporated herein by reference. CLAYTON WILLIAMS ENERGY, INC TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business.......................................................................... 2 Item 2. Properties........................................................................ 10 Item 3. Legal Proceedings................................................................. 14 Item 4. Submission of Matters to a Vote of Security Holders............................... 14 PART II Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters.............................................................. 15 Item 6. Selected Financial Data........................................................... 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................................ 17 Item 7A. Quantitative and Qualitative Disclosure About Market Risks........................ 23 Item 8. Financial Statements and Supplementary Data....................................... 24 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................................. 24 PART III Item 10. Directors and Executive Officers of the Registrant................................ 25 Item 11. Executive Compensation............................................................ 25 Item 12. Security Ownership of Certain Beneficial Owners and Management.................... 25 Item 13. Certain Relationships and Related Transactions.................................... 25 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K................... 26 GLOSSARY OF TERMS ................................................................................. 28 SIGNATURES......................................................................................... 31
1 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 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. The Company's total proved reserves at December 31, 2000 were 12.9 million barrels of oil and natural gas liquids and 28.3 Bcf of natural gas, with a present value of proved reserves of $307.5 million. Extensions and discoveries during 2000 added 4.1 million BOE of proved reserves, replacing 109% of the Company's 2000 net production. On a BOE basis, oil and natural gas liquids make up 73% of the Company's total proved reserves, and 85% of total proved reserves are classified as proved developed. The Company held interests in 557 gross (324.0 net) oil and gas wells and owned leasehold interests in 295,549 gross (159,368 net) undeveloped acres at December 31, 2000. COMPANY PROFILE EXPERTISE IN HORIZONTAL DRILLING A significant portion of the Company's proved oil and gas reserves are concentrated in the Cretaceous Trend (the "Trend") in Robertson, Burleson and Brazos Counties, Texas, which includes the Austin Chalk, Buda, and Georgetown formations. Most of the wells in this core area are horizontal wells, and many have multiple laterals in different producing zones and formations. The Company has a high degree of expertise in horizontal drilling and completion techniques, and believes that its technical knowledge can be utilized in other areas where horizontal drilling is being effectively employed, such as in the horizontal gas play in the Delaware Basin of West Texas targeting the Devonian and Montoya formations. 2 AGGRESSIVE EXPLORATION PROGRAM Since 1997, the Company has become increasingly aggressive in generating and drilling exploratory prospects in order to reduce its dependence on Trend drilling for future production and reserve growth. Currently, 82% of the Company's planned capital expenditures for 2001 relate to exploration activities, as compared to actual exploratory expenditures of 63% in 2000, 59% in 1999 and 67% in 1998. During 2000, the Company spent $56.7 million on exploratory prospects, including $17.5 million on seismic and leasing activities and $39.2 million on drilling activities. On these prospects, the Company drilled 19 gross (10.6 net) exploratory wells, of which 9 gross (5.8 net) were completed as producers. Exploratory prospects generally involve a higher degree of risk than development prospects, but may also offer a higher reserve potential and rate of return on investment. EXPLOITATION OF CORE AREAS The Company maintains an active workover, recompletion and exploitation program designed to increase production and reserve values from its core oil and gas properties. In the Trend, the Company has conducted cyclic water stimulations (water fracs) on most of the mature wells in this area. The Company's water frac operations in the Trend have proven to be successful in accelerating production, increasing reserves, and extending economic lives of these wells. In addition, the Company has further exploited portions of its acreage in the Trend by conducting extensive 3-D seismic surveys that have been successful in adding production and reserves from the deeper Cotton Valley Pinnacle Reef/Sands formations. CONTROL OF OPERATIONS The Company seeks to serve as operator of the wells in which it owns a significant interest. As operator, the Company is in a better position to (i) control the timing and plans for future drilling and exploitation efforts, (ii) control costs of drilling, completing and producing oil and gas wells and (iii) market its oil and gas production. At December 31, 2000, the Company was the operator of 439 wells, or 79% of the 557 total wells in which it has a working interest. On a BOE basis, production from these operated wells represented 92% of the Company's total net oil and gas production for 2000. Serving as operator, however, does not necessarily assure the Company of full control over drilling and completion activities. Presently, the oil and gas industry is experiencing strong demand for drilling rigs and other well-related services, resulting in shortages in available equipment and trained personnel. The Company may not be able to control the timing and cost of its future drilling and exploitation efforts to the extent desired due to such shortages. ADAPTABLE TO CHANGES The Company is adaptable to changes in economic conditions caused by fluctuations in product prices, results of exploration activities, competition for leases and drilling equipment, the availability of capital resources, and other events which require flexibility and prompt, decisive action. As economic conditions change, favorably or unfavorably, or as opportunities for growth in reserves and production are identified, the Company can make appropriate changes to its planned capital or exploratory expenditures. However, the Company's ability to increase its planned expenditures will be limited to the availability of its capital resources (see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - LIQUIDITY AND CAPITAL RESOURCES"). DRILLING, EXPLORATION AND PRODUCTION ACTIVITIES Following is a discussion of the Company's significant drilling, exploration and production activities during 2000, together with its plans for capital and exploratory expenditures in 2001. Under current economic conditions, the Company presently plans to spend $91.8 million on exploration and development activities during 2001. The Company may increase or decrease its planned activities for 2001, depending upon drilling results, product prices, the availability of capital resources, and other factors affecting the economic viability of such activities. 3 THE TREND During 2000, the Company continued to exploit its properties in the Trend by spending $20.9 million to drill 15 gross (14.1 net) horizontal wells in the Giddings Field in Burleson and Robertson Counties, Texas and to conduct 19 water fracs on existing wells in this area. The Company held 158,276 net acres in the Trend at December 31, 2000, of which approximately 29% were undeveloped. At the present time, the Company does not plan to drill Trend wells on a significant portion of this undeveloped acreage based on production performance of wells previously drilled in the area. Instead, the Company plans to spend approximately $10.4 million during 2001 to further exploit the developed portion of its Trend acreage by drilling 11 horizontal wells in areas that warrant development on an increased density basis. A portion of the acreage in this area is also prospective for Cotton Valley Pinnacle Reefs/Sands exploration activities (see "COTTON VALLEY PINNACLE REEFS/SANDS"). The Company's current production of oil and gas in the Trend is derived principally from the Austin Chalk formation. At December 31, 2000, the Company had interests in 329 gross (255.0 net) producing wells in the Trend. For the year ended December 31, 2000, the Company's daily net production in the Trend averaged approximately 5,311 Bbls of oil and 4.2 MMcf of gas. The Company operates 85% of its wells in the Trend. COTTON VALLEY PINNACLE REEFS/SANDS Since 1997, the Company has been actively exploring for gas reserves in the Cotton Valley Pinnacle Reef play on a portion of its Trend acreage in Robertson County, Texas. As opposed to Trend formations, which are encountered at depths of 5,500 to 7,000 feet in this area, Cotton Valley Pinnacle Reefs are encountered at depths below 15,000 feet. During 2000, the Company, subject to vendor financing arrangements, drilled and completed three producing Cotton Valley Reef wells and owned a 14% working interest in two non-operated Cotton Valley Reef wells that were dry holes. During the fourth quarter of 2000, combined gas production from these five wells averaged 26.1 MMcf per day (12.5 MMcf per day to the Company's interest, net of royalties and vendor financing arrangements). At December 31, 2000, the Company was in the process of drilling two additional Cotton Valley Pinnacle Reef wells, the Lee Fazzino #1 and the Big Red #1. The Company owns a 100% working interest in each well, and neither well is subject to vendor financing arrangements. Although the Big Red #1 was determined to be a dry hole, the Company completed the Lee Fazzino #1 as a producer, and is in the process of testing the well at various flow rates to establish its optimum deliverability. The Lee Fazzino #1 is presently producing at a rate of 23 MMcf per day with 8,200 psi of flowing tubing pressure. While the Company is encouraged by these preliminary rates, the Company cannot accurately predict future production rates and ultimate reserves attributable to the Lee Fazzino #1 at this time due to the well's limited production history. During 2000, the Company spent a total of $21.7 million in the Cotton Valley Reef area. Of this total, $15.7 million was spent on drilling and completion activities, and $6 million was spent primarily on the construction of a gas plant and related pipelines and a 3-D seismic shoot on the southern portion of the Company's acreage block in Robertson County, Texas. In addition, the Company spent $4.8 million to drill two wells in Robertson County, Texas, targeting Cotton Valley Sands at a depth of 12,200 to 12,850 feet. The first well, the Mary Muse #1, had to be abandoned due to an underground blowout during drilling, and the Mary Muse #1R was drilled and completed as a replacement well. The Company is presently evaluating the results of this well to determine the potential for future Cotton Valley Sands drilling and for possible recompletions in existing and future Cotton Valley Pinnacle Reef wells. 4 During 2001, the Company plans to spend $14.3 million in the Cotton Valley Pinnacle Reef/Sands area to complete the wells in progress at December 31, 2000 and to drill and complete the Neyland #1, the Company's eighth operated Pinnacle Reef well on which drilling operations were commenced in February 2001. After the Neyland #1, the Company plans to review its 3-D seismic data and results of wells drilled to date before commencing further drilling in this area. SOUTH LOUISIANA During 2000, the Company began establishing a new core area of operation in South Louisiana. Last year the Company assembled an experienced team of consulting geologists and geophysicists to identify drilling prospects in South Louisiana based on 3-D seismic data. As a result, the Company expects to drill a total of 23 wells in 2001 primarily in Plaquemines Parish, Louisiana and in the Sweetlake area of Cameron Parish, Louisiana. PLAQUEMINES PARISH During 2000, the Company drilled 2 gross (2.0 net) wells to the Miocene formation, one of which is productive, and spent $14.4 million, of which $10.5 million was attributable to seismic and leasing activities. In addition, the Company is currently completing 2 gross (1.9 net) productive wells drilled after year-end. Production facilities for these three productive wells are being constructed and are scheduled for completion during the second quarter of 2001. The Company has identified 21 additional 3-D prospects and plans to drill 15 of these prospects during the remainder of 2001. In the aggregate, the Company plans to spend $38.9 million on seismic, leasing and drilling activities in Plaquemines Parish during 2001. SWEETLAKE During 2000, the Company drilled 5 gross (2.4 net) Miocene wells in this area, of which 3 gross (1.5 net) are productive, and spent $6.1 million on seismic, leasing and drilling activities. During 2001, the Company has drilled 4 gross (2.2 net) additional wells, of which 2 gross (1.0 net) are productive and are expected to be on production by the end of April. The Company has identified five additional 3-D prospects and plans to drill two of these prospects during the remainder of 2001. In the aggregate, the Company plans to spend $5.9 million on seismic, leasing and drilling activities in the Sweetlake area during 2001. WEST TEXAS The Company plans to utilize its horizontal drilling expertise to explore for gas reserves in the Delaware Basin of West Texas targeting the Devonian and Montoya formations. The Company has acquired acreage in the Block 16 Field in Ward County and other areas in West Texas, and plans to spend $7.5 million for leasing and drilling activities in this area in 2001. NEW MEXICO During 2000, the Company drilled 20 gross (16 net) wells in Eddy County, New Mexico and spent $10.4 million on developmental drilling activities, targeting the Grayburg, San Andres, and Yeso formations. The Company plans to spend $5.5 million in New Mexico to drill and complete 16 gross (8.8 net) wells during 2001, of which 9 gross (4.5 net) have been drilled and completed as producers during the first quarter of 2001. OTHER EXPLORATION ACTIVITIES SOUTH TEXAS The Company participated in 6 gross (2.3 net) wells in Duval and Dewitt Counties, Texas during 2000 and spent a total of $4.8 million on seismic, leasing and drilling activities in this area. Of these six wells, 4 gross (1.7 net) wells are productive. During 2001, the Company plans to spend $2.3 million in South Texas to participate in two wells, one of which is non-operated. 5 BOSSIER SANDS The Company has begun an exploration project in the Bossier Sands play in Leon, Henderson, Freestone and Anderson Counties, Texas. The Bossier Sand formation is encountered in this area at depths of 14,000 to 15,000 feet. The Company plans to spend $6 million in 2001 on leasing and drilling activities in this area. 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. In the event 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 (two of which were constructed in connection with the Company's Cotton Valley Pinnacle Reef play), one liquids extraction plant and three compressor stations. Most of the Company's gas gathering and processing activities exist to facilitate the transportation and marketing of the Company's oil and gas production. 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. 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 6 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. All of the states in which the Company operates generally 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 also 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 Nos. 636, 637 and 638, 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 presently 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. 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 which may have the effect of reducing 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 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, regulations and lease provisions may substantially increase the cost of exploring for, developing, producing or processing oil and gas and may prevent or delay the commencement 7 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. 8 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 96 full-time employees, none of whom is subject to a collective bargaining agreement. The Company considers its relations with its employees to be good. OFFICERS AND DIRECTORS The following table sets forth certain information concerning officers and directors of the Company.
NAME AGE POSITION WITH THE COMPANY ------------------------------------- --------- -------------------------------------------- Clayton W. Williams 69 Chairman of the Board, President, Chief Executive Officer and Director L. Paul Latham 49 Executive Vice President, Chief Operating Officer and Director Mel G. Riggs 46 Senior Vice President - Finance, Secretary, Treasurer, Chief Financial Officer and Director Jerry F. Groner 38 Vice President - Land and Lease Administration and Director Robert C. Lyon 64 Vice President - Gas Gathering and Marketing Patrick C. Reesby 48 Vice President - New Ventures T. Mark Tisdale 44 Vice President and General Counsel Stanley S. Beard 60 Director Robert L. Parker 77 Director Jordan R. Smith 66 Director
OFFICES The Company leases approximately 40,000 square feet of office space in Midland, Texas and approximately 4,000 square feet of office space in Houston, Texas. 9 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, 2000, the Company had interests in 557 gross (324.0 net) oil and gas wells and owned leasehold interests in 295,549 gross (159,368 net) undeveloped acres. RESERVES The following table sets forth certain information as of December 31, 2000 with respect to the Company's estimated proved oil and gas reserves, present value of proved reserves and standardized measure of discounted future net cash flows.
PROVED PROVED DEVELOPED UNDEVELOPED TOTAL --------- ----------- ----- (DOLLARS IN THOUSANDS) Oil and natural gas liquids (MBbls)............................ 10,565 2,346 12,911 Gas (MMcf)..................................................... 26,278 2,030 28,308 MBOE........................................................... 14,945 2,684 17,629 Present value of proved reserves............................... $ 284,004 $ 23,452 $ 307,456 Standardized measure of discounted future net cash flows....... $ 232,064
The following table sets forth certain information as of December 31, 2000 regarding the Company's proved oil and gas reserves in each of its principal producing areas.
PROVED RESERVES ----------------------------------- PERCENTAGE OF TOTAL OIL PERCENT OF PRESENT VALUE PRESENT VALUE OIL (a) GAS EQUIVALENT TOTAL OIL OF PROVED OF PROVED (MBbls) (MMcf) (MBOE) EQUIVALENT RESERVES RESERVES ------- ------ ---------- ---------- ------------- -------------- (IN THOUSANDS) Trend .............. 10,860 7,335 12,083 68.5% $ 153,940 50.1 % Cotton Valley........ - 7,654 1,276 7.2% 57,990 18.9 % New Mexico / West Texas......... 1,722 3,846 2,363 13.4% 33,074 10.7 % Louisiana............ 182 3,290 730 4.1% 29,770 9.7 % East Texas........... 82 4,246 789 4.5% 20,010 6.5 % Other .............. 65 1,937 388 2.3% 12,672 4.1 % -------- -------- --------- -------------- --------------- ---------------- Total......... 12,911 28,308 17,629 100.0% $ 307,456 100.0 % ======== ======== ========= ============== =============== ================
--------------------- (a) Includes natural gas liquids. The estimates of proved reserves at December 31, 2000, and their estimated present value, were based primarily on a report prepared by Williamson Petroleum Consultants, Inc. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from fixed-price contracts. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. The estimated present value of proved reserves does not give effect to indirect expenses such as general and administrative expenses, debt service and future income tax expense or to depletion, depreciation and amortization. 10 In accordance with applicable guidelines of the SEC, the estimates of the Company's proved reserves and the present value of proved reserves set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Estimated quantities of proved reserves and their present value are affected by changes in oil and gas prices. Gas prices increased substantially from December 31, 1999 to December 31, 2000, resulting in significant increases in the Company's estimated present value and estimated reserve quantities. The weighted average of the sales prices utilized for the purposes of estimating the Company's proved reserves and the present value of proved reserves as of December 31, 2000 were $25.12 per Bbl of oil and natural gas liquids and $10.09 per Mcf of gas, as compared to $25.09 per Bbl of oil and $2.36 per Mcf of gas as of December 31, 1999. Since December 31, 2000, gas prices have decreased by approximately 50%. The Company estimates that a $1.00 per Bbl change in oil price and a $.10 per Mcf change in gas price from those utilized in calculating the present value of proved reserves would change the present value by $8 million and $1.9 million, respectively. Based on product prices of $26.33 per Bbl of oil and natural gas liquids ($28.00 NYMEX) and $4.68 per Mcf of natural gas ($5.00 NYMEX), the Company's present value of proved reserves at December 31, 2000 would have been approximately $214 million, and proved reserves would have been approximately 17.2 million BOE. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and their present value, and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company's control. The reserve information shown is estimated. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data, the precision of the engineering and geological interpretation, and judgment. As a result, estimates of different engineers often vary. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which the Company's business or the oil and natural gas industry in general are subject. Since January 1, 2000, 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. 11 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, -------------------------------------------------------------------------- 2000 1999 1998 ---------------------- ---------------------- ---------------------- GROSS NET GROSS NET GROSS NET -------- --------- --------- --------- --------- --------- DEVELOPMENT WELLS: Oil................. 41 33.0 3 2.4 10 6.6 Gas................. 11 1.7 1 .3 - - Dry................. 1 .4 1 .5 - - -------- --------- --------- ------------- ------ ----- Total............ 53 35.1 5 3.2 10 6.6 ======== ========= ========= ============= ====== ===== EXPLORATORY WELLS: Oil................. 1 .5 1 .6 2 .8 Gas................. 8 5.3 2 2.0 4 2.2 Dry................. 10 4.8 3 1.1 10 6.6 -------- --------- --------- ------------- ------ ----- Total............ 19 10.6 6 3.7 16 9.6 ======== ========= ========= ============= ====== ===== TOTAL WELLS: Oil................. 42 33.5 4 3.0 12 7.4 Gas................. 19 7.0 3 2.3 4 2.2 Dry................. 11 5.2 4 1.6 10 6.6 -------- --------- --------- ------------- ------ ----- Total............ 72 45.7 11 6.9 26 16.2 ======== ========= ========= ============= ====== =====
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. PRODUCTIVE WELL SUMMARY The following table sets forth certain information regarding the Company's ownership, as of December 31, 2000, of productive wells in the areas indicated.
OIL GAS TOTAL -------------------- ------------------ ---------------------- GROSS NET GROSS NET GROSS NET ----- --- ----- --- ----- --- Trend ................. 307 239.8 22 15.2 329 255.0 New Mexico / West Texas............ 49 31.3 11 1.2 60 32.5 East Texas.............. - - 117 11.5 117 11.5 South Texas............. 1 .7 26 8.3 27 9.0 Louisiana............... 4 2.2 5 2.3 9 4.5 Cotton Valley........... - - 5 5.0 5 5.0 Other................... 7 5.6 3 .9 10 6.5 -------- --------- --------- --------- --------- --------- Total............ 368 279.6 189 44.4 557 324.0 ======== ========= ========= ========= ========= =========
12 The Company seeks to serve 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, 2000, the Company was the operator of 439 wells, or 79% of the 557 total wells in which it has a working interest. On a BOE basis, production from these operated wells represented 92% of the Company's total net oil and gas production for 2000. 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, ------------------------------------------------ 2000 1999 1998 ---- ---- ---- OIL AND GAS PRODUCTION DATA: Oil (MBbls)............................. 2,386 1,876 2,528 Gas (MMcf).............................. 8,047 4,847 4,833 Total (MBOE)............................ 3,727 2,684 3,334 AVERAGE OIL AND GAS SALES PRICE (1): Oil ($/Bbl)............................. $ 29.44 $ 17.44 $ 16.20 Gas ($/Mcf)(2).......................... $ 4.06 $ 2.34 $ 2.35 AVERAGE PRODUCTION COSTS Lease operations ($/BOE)(3)............. $ 4.92 $ 4.18 $ 4.27
----------------------- (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. Through 2000, the Company has reported its natural gas production on a wet stream basis, whereby the Btu content of natural gas liquids was included with natural gas. Effective December 31, 2000, the Company changed its method of estimating future natural gas production from a wet stream to a dry stream, whereby the natural gas liquids to be derived from natural gas production will be measured in barrels and will be included with oil production. Beginning in 2001, the Company will report actual production of oil, natural gas, and natural gas liquids on a dry stream basis to be consistent with its method of estimating production and reserves. 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, -------------------------------------------------- 2000 1999 1998 ---- ---- ---- (IN THOUSANDS) Property Acquisitions: Proved.................................. $ - $ - $ 7,077 Unproved................................ 11,131 3,221 10,602 Developmental Costs....................... 36,510 8,199 7,285 Exploratory Costs......................... 32,297 6,912 22,319 ------------------ ------------------ ------------------ Total................................... $ 79,938 $ 18,332 $ 47,283 ================== ================== ==================
13 ACREAGE The following table sets forth certain information regarding the Company's developed and undeveloped leasehold acreage as of December 31, 2000 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....... 125,828 111,316 60,145 46,960 185,973 158,276 Louisiana................... 1,355 1,178 24,581 20,100 25,936 21,278 West Texas / New Mexico..... 2,792 2,047 22,477 10,417 25,269 12,464 East Texas.................. 2,477 1,665 - - 2,477 1,665 Other (1)................... 16,081 6,600 188,346 81,891 204,427 88,491 ----------- ----------- ----------- ----------- ----------- ----------- Total................ 148,533 122,806 295,549 159,368 444,082 282,174 =========== =========== =========== =========== =========== ===========
-------------- (1) Net undeveloped acres are attributable to the following areas: the Glen Rose area in Southeast Texas - 22,893; Colorado - 18,684; Alabama - 13,486; Mississippi - 9,542; Wyoming - 8,023; South Texas - 6,665, and other - 2,598. 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 filed in October 1995 styled THE STATE OF TEXAS, ET AL V. UNION PACIFIC RESOURCES COMPANY ET AL, which case is 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. The Company is neither a common purchaser nor common carrier of oil. The plaintiffs have not undertaken any actions to prosecute this case since January 1996. Lead counsel for the plaintiffs withdrew from the case in 1996, and counsel for the individual named plaintiffs filed a Motion to Withdraw from the case in 1998. There has been no effort by the plaintiffs to have this case certified as a class since January 1996. Management of the Company believes there is no merit to the allegations as they relate to the Company or its operations. In addition, the Company is a defendant or codefendant in minor lawsuits that have arisen in the ordinary course of business. While the outcome of these lawsuits cannot be predicted with certainty, management does not expect any of these to have a material adverse effect on the Company's consolidated financial condition or results of operations. 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, 2000. 14 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, 2000, there were approximately 1,600 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, 2000: Fourth Quarter...................................... $ 43 15/16 $ 19 1/4 Third Quarter....................................... 46 1/8 27 Second Quarter...................................... 34 15/16 13 3/4 First Quarter....................................... 16 1/4 9 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
The quotations in the table above reflect inter-dealer prices without retail markups, markdowns or commissions. On March 20, 2001, the last reported sale price for the Common Stock on the Nasdaq Stock Market's National Market was $18 1/4. 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. 15 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, 2000 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, ----------------------------------------------------------------------- 2000 1999 1998 1997 1996 ---------- ---------- ---------- ---------- --------- (IN THOUSANDS, EXCEPT PER SHARE) STATEMENT OF OPERATIONS DATA: Revenues: Oil and gas sales................. $ 103,150 $ 44,366 $ 51,932 $ 70,929 $ 60,610 Natural gas services.............. 6,682 3,684 3,795 4,559 4,281 ----------- ----------- ----------- ----------- ----------- Total revenues............... 109,832 48,050 55,727 75,488 64,891 ----------- ----------- ----------- ----------- ----------- Costs and expenses: Lease operations.................. 18,346 11,222 14,237 16,205 14,776 Exploration: Abandonments and impairments. 12,657 5,245 16,128 2,692 597 Seismic and other............ 7,953 1,418 4,501 7,629 1,036 Natural gas services.............. 5,591 3,098 3,242 3,955 3,437 Depreciation, depletion and amortization 27,794 20,810 31,665 31,273 23,758 Impairment of property and equipment - 81 8,493 236 1,186 General and administrative........ 5,014 3,929 4,299 4,181 3,266 Stock-based employee compensation. 937 - - - - ----------- ----------- ----------- ----------- ----------- Total costs and expenses..... 78,292 45,803 82,565 66,171 48,056 ----------- ----------- ----------- ----------- ----------- Operating income (loss)...... 31,540 2,247 (26,838) 9,317 16,835 ----------- ----------- ----------- ----------- ----------- Other income (expense): Interest expense.................. (2,310) (2,893) (2,384) (1,767) (3,440) Gain on sales of property and equipment 1,031 10,926 53 155 293 Other income...................... 269 474 85 62 42 ----------- ----------- ----------- ----------- ----------- Total other income (expense). 1,010 8,507 (2,246) (1,550) (3,105) ----------- ----------- ----------- ----------- ----------- Income (loss) before income taxes..... 30,530 10,754 (29,084) 7,7671 3,730 Income tax expense.................... 2,717 - - - - ----------- ----------- ----------- ----------- ----------- Net income (loss)..................... $ 27,813 $ 10,754 $ (29,084) $ 7,767 $ 13,730 =========== =========== =========== =========== =========== Net income (loss) per common share: Basic............................. $ 3.02 $ 1.19 $ (3.27) $ .87 $ 1.80 =========== =========== =========== =========== =========== Diluted........................... $ 2.91 $ 1.18 $ (3.27) $ .85 $ 1.76 =========== =========== =========== =========== =========== Weighted average common shares outstanding: Basic............................. 9,211 9,005 8,905 8,888 7,624 =========== =========== =========== =========== =========== Diluted........................... 9,543 9,148 8,905 9,094 7,800 =========== =========== =========== =========== =========== OTHER DATA: Net cash provided by operating activities $ 72,471 $ 24,738 $ 33,505 $ 39,324 $ 40,306 EBITDAX (1)........................... $ 81,280 $ 30,075 $ 34,324 $ 51,729 $ 43,857
DECEMBER 31, ------------------------------------------ 2000 1999 1998 ---------- ---------- --------- (IN THOUSANDS) BALANCE SHEET DATA: Working capital (deficit)........................................... $ (18,656) $ (6,649) $ (15,848) Total assets........................................................ 164,864 109,166 120,653 Long-term debt...................................................... 30,000 30,500 39,100 Stockholders' equity................................................ 85,777 56,117 44,394
------------ (1) EBITDAX refers to earnings before interest expense, income taxes, depreciation, depletion and amortization, impairment of property and equipment, exploration costs, other non-cash charges 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. 16 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, 2000, and results of operations and cash flows for each of the three years in the period ended December 31, 2000. The Company's historical Consolidated Financial Statements and notes thereto included 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. However, since 1997, the Company has become increasingly aggressive in generating and drilling exploratory prospects in other areas to reduce its dependence on Trend drilling for future production and reserve growth. Currently, 82% of the Company's planned capital expenditures for 2001 relate to exploration activities, as compared to actual exploratory expenditures of 63% in 2000, 59% in 1999 and 67% in 1998. During 2000, the Company spent $56.7 million on exploratory prospects including $17.5 million on seismic and leasing activities and $39.2 million on drilling activities. On these prospects, the Company drilled 19 gross (10.6 net) exploratory wells, of which 9 gross (5.8 net) were completed as producers. The Company follows the successful efforts method of accounting for its oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized and amortized using the unit-of-production method based on estimated proved reserves. Costs of unproved properties are initially capitalized. Those properties with significant acquisition costs are periodically assessed and any impairment in value is charged to expense. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate groups based on the Company's historical experience, acquisition dates and average lease terms. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if and when the well is determined to be unsuccessful. 17 RESULTS OF OPERATIONS The following table sets forth certain operating information of the Company for the periods presented.
YEAR ENDED DECEMBER 31, ----------------------------------- 2000 1999 1998 -------- -------- --------- OIL AND GAS PRODUCTION DATA: Oil (MBbls)....................................................... 2,386 1,876 2,528 Gas (MMcf)........................................................ 8,047 4,847 4,833 Total (MBOE)...................................................... 3,727 2,684 3,334 AVERAGE OIL AND GAS SALES PRICES (1): Oil ($/Bbl)....................................................... $ 29.44 $ 17.44 $ 16.20 Gas ($/Mcf)....................................................... $ 4.06 $ 2.34 $ 2.35 OPERATING COSTS AND EXPENSES ($/BOE PRODUCED): Lease operations.................................................. $ 4.92 $ 4.18 $ 4.27 Oil and gas depletion............................................. $ 7.18 $ 7.46 $ 9.24 General and administrative........................................ $ 1.35 $ 1.46 $ 1.29 NET WELLS DRILLED (2): Exploratory Wells................................................. 10.6 3.7 9.6 Developmental Wells............................................... 35.1 3.2 6.6
(1) Includes effects of hedging transactions. (2) Excludes wells being drilled or completed at the end of each period. 2000 COMPARED TO 1999 REVENUES Oil and gas sales increased 132% from $44.4 million in 1999 to $103.2 million in 2000 due to significantly higher oil and gas prices and production levels. The Company's average price per barrel of oil increased 69% while average gas prices increased 74%. Gas production increased 66% due primarily to added production from the Cotton Valley Pinnacle Reef area. Oil production increased 27% due primarily to enhanced production from the Company's horizontal drilling and water frac programs in the Trend, and to a lesser extent, from the Company's on-going developmental drilling program in Eddy County, New Mexico. As of December 31, 2000, the Company, as operator, has drilled and completed five wells in the Cotton Valley Pinnacle Reef area, four of which were drilled under a vendor financing arrangement. During the fourth quarter of 2000, combined gas production from these five wells averaged 26.1 MMcf per day (12.5 MMcf per day to the Company's interest, net of royalties and vendor financing arrangements). At December 31, 2000, the Company was in the process of drilling two additional Cotton Valley Pinnacle Reef wells, the Lee Fazzino #1 and the Big Red #1. The Company owns a 100% working interest in each well, and neither well is subject to vendor financing arrangements. Although the Big Red #1 was determined to be a dry hole, the Company completed the Lee Fazzino #1 as a producer, and is in the process of testing the well at various flow rates to establish its optimum deliverability. The Lee Fazzino #1 is presently producing at a rate of 23 MMcf per day with 8,200 psi of flowing tubing pressure. While the Company is encouraged by these preliminary rates, the Company cannot accurately predict future production rates and ultimate reserves attributable to the Lee Fazzino #1 at this time due to the well's limited production history. 18 COSTS AND EXPENSES Lease operations expenses increased 63% from $11.2 million in 1999 to $18.3 million in 2000 while oil and gas production on a BOE basis increased 39%, resulting in an 18% increase in lease operations expenses on a BOE basis from $4.18 per BOE in 1999 to $4.92 per BOE in 2000. Most of the increase in production costs on a BOE basis was a direct result of higher production taxes caused by a significant increase in product prices. Exploration costs increased 207% from $6.7 million in 1999 to $20.6 million in 2000 due primarily to the charge-off during 2000 of $8.4 million of dry hole costs, $4.3 million of unproved property impairments, and $7.6 million of seismic costs, as compared to $1.2 million of dry hole costs, $4 million of unproved property impairments, and $1.1 million of seismic costs during 1999. Dry hole costs during 2000 include $2.6 million in the Cotton Valley area, $2.6 million in South Louisiana and $2.4 million in South Texas. Unproved property impairments in 2000 relate primarily to acreage in the Glen Rose area of Texas and, to a lesser extent, acreage in Mississippi and Louisiana. Substantially all of the seismic costs in 2000 are attributable to exploratory prospects being generated in South Louisiana and to an additional 3-D seismic project in the Cotton Valley Pinnacle Reef area. Because the Company follows the successful efforts method of accounting, the Company's results of operations may be adversely affected during any accounting period in which seismic costs, exploratory dry hole costs, and unproved property impairments are expensed. Depreciation, depletion and amortization ("DD&A") expense increased 34% from $20.8 million in 1999 to $27.8 million in 2000 due primarily to a 39% increase in oil and gas production on a BOE basis, offset in part by a 4% decrease in the Company's average depletion rate per BOE. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The decline in average depletion rate per BOE from $7.46 in 1999 to $7.18 in 2000 was primarily due to higher reserve estimates attributable to improved product prices. General and administrative ("G&A") expenses increased 28% from $3.9 million in 1999 to $5 million in 2000 due primarily to higher personnel costs attributable to increased levels of drilling and operating activities. Low product prices caused the Company to curtail its operations early in 1999 and implement cost reduction measures consisting primarily of personnel layoffs and salary reductions. As product prices improved during the last half of 1999 and into 2000, the Company resumed drilling and operating activities and reversed many of these cost reduction measures. A provision for stock-based employee compensation of $937,000 was made during 2000 pursuant to the requirements of Financial Accounting Standards Board Interpretation No. 44 (see Note 6 to the accompanying consolidated financial statements). No corresponding provision was required during 1999. Since the amount of this non-cash provision is based on the quoted market price of the Company's common stock, future results of operations may be subject to significant volatility. INTEREST EXPENSE AND OTHER Interest expense decreased 21% from $2.9 million in 1999 to $2.3 million in 2000 due primarily to lower average levels of indebtedness on the Company's secured bank credit facility (the "Credit Facility"), offset in part by higher interest rates and lower capitalized interest. The average daily principal balance outstanding on the Credit Facility during 2000 was $30.3 million compared to $42 million in 1999, while the effective annual interest rate, including bank fees, was 9.2% compared to 8.1% in 1999. Capitalized interest in 2000 was $483,000 compared to $547,000 in 1999. Gains on sales of property and equipment decreased from $10.9 million in 1999 to $1 million in 2000. During 2000, the Company sold its interest in a prospect in Duval County, Texas for $1 million, resulting in a gain of $1 million. During 1999, the Company recorded a gain of $8.3 million on the sale of its interest in the Jalmat Field in Lea County, New Mexico for $12.5 million, and a gain of $1.8 million on the sale of its interest in eight non-operated gas wells in Matagorda County, Texas for $5.2 million. 19 INCOME TAXES During 2000, the Company's pre-tax income was sufficient to cause its deferred tax liabilities to exceed its deferred tax assets, resulting in an income tax provision of $2.7 million (9% effective tax rate) in 2000 as compared to no income tax provision in 1999. The Company expects to record a provision for income taxes in future periods equal to approximately 35% of its pre-tax income. 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 $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. 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. 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. 20 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 Credit Facility. The average daily principal balance outstanding on the Credit Facility during 1999 was $42 million compared to $40.8 million in 1998, while the effective annual interest rate, including bank fees, during both years 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. 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 2001, and the expected capital resources needed to finance such plans. CAPITAL EXPENDITURES The Company presently plans to spend $91.8 million on exploration and development activities during 2001, including $44.8 million in South Louisiana, $14.3 million in the Cotton Valley Pinnacle Reef area, $10.4 million in the Trend, $7.5 million in West Texas, $6 million in the Bossier Sand area in Texas, $5.5 million in Southeast New Mexico, and $3.3 million on various other projects. Approximately 82% of these planned expenditures apply to exploratory prospects, as compared to approximately 63% in 2000. Exploratory prospects generally involve a higher degree of risk than developmental prospects, but may also offer a higher reserve potential and rate of return on investment. See "BUSINESS - DRILLING, EXPLORATION AND PRODUCTION ACTIVITIES." The Company may increase or decrease its planned activities for 2001, depending upon drilling results, product prices, the availability of capital resources, and other factors affecting the economic viability of such activities. 21 CAPITAL RESOURCES GENERAL The Company believes that the combination of cash provided by operations and funds available under the Credit Facility will be adequate to fund the Company's operations and projected capital and exploratory expenditures during 2001. 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 and the Company's success in developing and producing new reserves, there can be no assurance that the Company's capital resources will be sufficient to sustain the Company's exploratory and development activities. WORKING CAPITAL AND CASH FLOW During 2000, the Company generated cash flow from operating activities of $72.5 million, received $1.1 million from the sale of property and equipment, spent $72.6 million on capital expenditures and repaid $500,000 on the Credit Facility. The Company's working capital deficit increased from $6.6 million at December 31, 1999 to $18.7 million at December 31, 2000 due primarily to a significant increase in drilling and exploration activities in progress at the end of 2000. The Company was utilizing nine drilling rigs at December 31, 2000 compared to three at December 31, 1999. Three of the current period wells in progress were Cotton Valley Pinnacle Reefs/Sands wells being drilled 100% by the Company, as compared to only one Pinnacle Reef well being drilled through a vendor financing arrangement at the end of 1999. Accordingly, accounts payable and accrued liabilities at December 31, 2000 related to drilling and exploration activities were significantly higher than December 31, 1999. The Company's working capital deficit generally is a function of its cash management process. The Company applies most of its available cash toward the repayment of the Credit Facility, which is classified as a non-current liability. As advances are made on the Credit Facility to pay current liabilities (including accrued drilling and exploration costs), the Company's working capital increases. Therefore, to more effectively measure the Company's working capital position at any balance sheet date, the loan agreement to the Credit Facility provides for the inclusion of funds available on the Credit Facility as a current asset in the computation of working capital. 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, 2000, the borrowing base was $50 million and the outstanding advances were $30 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. 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 and non-financial covenants at December 31, 2000. Effective January 1, 2001, the borrowing base was increased to $55 million. 22 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 volume of oil and gas production for the year ended December 31, 2000, 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 annual gross revenues of approximately $3.2 million. From time to time, the Company utilizes fixed-price commodity swaps and collars (collectively, fixed-price contracts) to reduce its exposure to unfavorable changes in oil and gas prices. Since the Company's hedging objective is to optimize the price received for its oil and natural gas production, the Company generally enters into fixed-price contracts only when management of the Company believes that the quoted market prices for such commodities are likely to experience a sustained decline from then-current levels. While the use of fixed-price contracts limits the downside risk of price declines, such use may also limit any benefits that may be derived from price increases. When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. Collars contain a fixed floor price (put) and ceiling price (call). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike prices, then no payments are due from either party. The fixed-price contracts utilized by the Company differ from futures contracts in that there is not a contractual obligation that requires or permits the future physical delivery of the hedged products. 23 At December 31, 2000, the Company had open positions in the following fixed-price contracts: o Fixed-price oil swaps covering 34,000 barrels from April 2001 through October 2001 at an average price of $20.77 per barrel (ranging from a high of $21.55 in April 2001 to a low of $20.03 in October 2001). o Fixed-price oil collars covering 17,000 barrels 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. In addition, the Company had closed positions at December 31, 2000 in certain fixed-price oil swaps covering 687,000 barrels from January 2001 through December 2001 at an average price of $29.14 per barrel. These contracts were terminated in 2000 at an average price of $29.45 per barrel, resulting in an aggregate loss of $213,000. This loss was deferred at December 31, 2000 and will be recorded as a reduction in oil and gas revenues during the periods that correlate to the hedged production months. Subsequent to December 31, 2000, the Company entered into a fixed-price gas swap covering 940,000 MMBtu from February 2001 through April 2001 at an average price of $8.19 per MMBtu. The Company's position for February 2001 and March 2001 covering 650,000 MMBtu was terminated prior to maturity at an aggregate gain of $1.6 million. This gain will be recorded in oil and gas revenues during the periods that correlate to the hedged production months. Effective January 1, 2001, the Company adopted SFAS 133 which established new accounting and reporting requirements for derivative instruments and hedging activities. See Note 10 to the accompanying consolidated financial statements. INTEREST RATES All of the Company's outstanding indebtedness at December 31, 2000 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, 2000 of $30 million, a change in interest rates of 25 basis points would affect annual interest payments by $75,000. 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. 24 PART III ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The Information required by this Item is incorporated herein by reference to the Company's definitive proxy statement which will be filed with the Commission within 120 days after December 31, 2000. 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, 2000. 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, 2000. 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, 2000. 25 PART IV ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K FINANCIAL STATEMENTS AND SCHEDULES For a list of the consolidated financial statements filed as part of this Form 10-K, see the Index to Consolidated Financial Statements on page F-1. No financial statement schedules are required to be filed as a part of this Form 10-K. REPORTS ON FORM 8-K No reports on Form 8-K were filed during the quarter ended December 31, 2000. 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 Certificate of Amendment of Second Restated Certificate of Incorporation of Clayton Williams Energy, Inc., filed as an exhibit to the September 30, 2000 Form 10-Q **3.3 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., filed as an exhibit to the December 31, 1999 Form 10-K **10.2 First Amendment to Seventh Restated Loan Agreement dated as of July 1, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI Acquisitions, Inc., Bank One, Texas, N.A. and Union Bank of California, N.A., filed as an exhibit to the June 30, 2000 Form 10-Q **10.3 1993 Stock Compensation Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 33-68318 **10.4 First Amendment to 1993 Stock Compensation Plan, filed as an exhibit to the December 31, 1995 Form 10-K **10.5 Second Amendment to the 1993 Stock Compensation Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 33-68318 **10.6 Third Amendment to 1993 Stock Compensation Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 333-47232 **10.7 Fourth Amendment to 1993 Stock Compensation Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 333-47232 **10.8 Outside Directors Stock Option Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 33-68316
26
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT --------- ------------------------------------------------------------------------------------------------------ **10.9 First Amendment to Outside Directors Stock Option Plan, filed as an exhibit to the December 31, 1995 Form 10-K **10.10 Bonus Incentive Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 33-68320 **10.11 First Amendment to Bonus Incentive Plan, filed as an exhibit to the December 31, 1997 Form 10-K **10.12 Amended and Restated 401(k) Plan & Trust, filed as an exhibit to the December 31, 1995 Form 10-K **10.13 Second Amendment to Amended and Restated 401(k) Plan & Trust, filed as an exhibit to the December 31, 1995 Form 10-K **10.14 Third Amendment to Amended and Restated 401(k) Plan & Trust, filed as an exhibit to the December 31, 1995 Form 10-K **10.15 Executive Incentive Stock Compensation Plan, filed as an exhibit to the Form S-8 Registration Statement, Registration No. 33-92834 **10.16 First Amendment to Executive Incentive Stock Compensation Plan, filed as an exhibit to the December 31, 1996 Form 10-K **10.17 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 **10.18 Amendment to Consolidation Agreement dated August 7, 2000 among Clayton Williams Energy, Inc., Warrior Gas Co., Clayton W. Williams, Jr. and the Williams Companies, filed as an exhibit to the September 30, 2000 Form 10-Q **10.19 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 **10.20 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 *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
----------------- * Filed herewith ** Incorporated by reference to the filing indicated 27 GLOSSARY OF TERMS The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K. 3-D SEISMIC. An advanced technology method of detecting accumulations of hydrocarbons identified by the collection and measurement of the intensity and timing of sound waves transmitted into the earth as they reflect back to the surface. Bbl. One barrel, or 42 U.S. gallons of liquid volume. Bcf. One billion cubic feet. BOE. Equivalent barrels of oil, with natural gas converted to oil equivalents based on a ratio of six Mcf of natural gas to one Bbl of oil. Btu. British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit. COMPLETION. The installation of permanent equipment for the production of oil or gas. DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. DRY HOLE. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. EXPLORATORY WELL. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. EXTENSIONS AND DISCOVERIES. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. GROSS ACRES OR WELLS. Refers to the total acres or wells in which the Company has a working interest. HORIZONTAL DRILLING. A drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. MBbls. One thousand barrels. MBOE. One thousand BOE. Mcf. One thousand cubic feet. MMcf. One million cubic feet. NATURAL GAS LIQUIDS. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline. NET ACRES OR WELLS. Refers to gross acres or wells multiplied, in each case, by the percentage working interest owned by the Company. 28 NET PRODUCTION. Oil and gas production that is owned by the Company, less royalties and production due others. NYMEX. New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded. OIL. Crude oil or condensate. OPERATOR. The individual or company responsible for the exploration, development and production of an oil or gas well or lease. PRESENT VALUE OF PROVED RESERVES. The present value of estimated future revenues to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to nonproperty related expenses such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. PROVED RESERVES. The estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. ROYALTY. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. SEC. The United States Securities and Exchange Commission. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The after-tax present value of proved reserves determined in accordance with SEC guidelines. UNDEVELOPED ACREAGE. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. 29 WATER FRAC. A well stimulation technique whereby large volumes of water are injected at high rates into a well. The well is shut-in for a period of 10 days to two weeks and is then returned to production. The injected water is pumped into micro-pore spaces in the rock, thereby displacing oil into the fractures where it may be more readily produced. This process is generally performed during the initial completion process and may be repeated one or more times after initial completion. WORKING INTEREST. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden. WORKOVER. Operations on a producing well to restore or increase production. 30 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 21, 2001 ---------------------------------------------- President and Chief Executive Clayton W. Williams Officer and Director /s/ L. PAUL LATHAM Executive Vice President, March 21, 2001 ---------------------------------------------- Chief Operating Officer and L. Paul Latham Director /s/ MEL G. RIGGS * Senior Vice President - March 21, 2001 ---------------------------------------------- Finance, Secretary, Treasurer, Mel G. Riggs Chief Financial Officer and Director /s/ JERRY F. GRONER * Vice President - Land and March 21, 2001 ---------------------------------------------- Lease Administration and Jerry F. Groner Director /s/ STANLEY S. BEARD * Director March 21, 2001 ---------------------------------------------- Stanley S. Beard /s/ ROBERT L. PARKER * Director March 21, 2001 ---------------------------------------------- Robert L. Parker /s/ JORDAN R. SMITH * Director March 21, 2001 ---------------------------------------------- Jordan R. Smith * By: /s/ L. PAUL LATHAM ---------------------------------------------- L. Paul Latham ATTORNEY-IN-FACT
31 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 Shareholders 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, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Dallas, Texas March 2, 2001 F-2 CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
ASSETS DECEMBER 31, ----------------------------------- 2000 1999 --------------- ---------------- CURRENT ASSETS Cash and cash equivalents............................................. $ 2,384 $ 1,634 Accounts receivable: Oil and gas sales................................................. 15,534 9,846 Joint interest and other, net..................................... 4,102 2,661 Affiliates........................................................ 179 729 Inventory............................................................. 3,226 717 Deferred income taxes................................................. 601 - Prepaids and other.................................................... 2,246 313 --------------- ---------------- 28,272 15,900 --------------- ---------------- PROPERTY AND EQUIPMENT Oil and gas properties, successful efforts method..................... 501,542 436,831 Natural gas gathering and processing systems.......................... 13,302 9,810 Other................................................................. 10,572 10,350 --------------- ---------------- 525,416 456,991 Less accumulated depreciation, depletion and amortization............. (389,072) (363,985) --------------- ---------------- Property and equipment, net....................................... 136,344 93,006 --------------- ---------------- OTHER ASSETS............................................................... 248 260 --------------- ---------------- $ 164,864 $ 109,166 =============== ================ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable: Trade............................................................. $ 33,622 $ 13,648 Oil and gas sales................................................. 9,201 6,678 Affiliates........................................................ 2,642 1,417 Accrued liabilities and other......................................... 1,463 806 --------------- ---------------- 46,928 22,549 --------------- ---------------- LONG-TERM DEBT............................................................. 30,000 30,500 --------------- ---------------- DEFERRED INCOME TAXES...................................................... 2,159 - --------------- ---------------- 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 - 30,000,000 shares; issued - 9,254,352 shares in 2000 and 9,167,779 shares in 1999............................................. 925 917 Additional paid-in capital............................................ 72,529 70,690 Retained earnings (deficit)........................................... 12,323 (15,490) --------------- ---------------- 85,777 56,117 --------------- ---------------- $ 164,864 $ 109,166 =============== ================
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, ------------------------------------------------- 2000 1999 1998 -------------- ------------- -------------- REVENUES Oil and gas sales........................................ $ 103,150 $ 44,366 $ 51,932 Natural gas services..................................... 6,682 3,684 3,795 -------------- ------------- -------------- Total revenues....................................... 109,832 48,050 55,727 -------------- ------------- -------------- COSTS AND EXPENSES Lease operations......................................... 18,346 11,222 14,237 Exploration: Abandonments and impairments......................... 12,657 5,245 16,128 Seismic and other.................................... 7,953 1,418 4,501 Natural gas services..................................... 5,591 3,098 3,242 Depreciation, depletion and amortization................. 27,794 20,810 31,665 Impairment of property and equipment..................... - 81 8,493 General and administrative............................... 5,014 3,929 4,299 Stock-based employee compensation........................ 937 - - -------------- ------------- -------------- Total costs and expenses............................. 78,292 45,803 82,565 -------------- ------------- -------------- Operating income (loss).............................. 31,540 2,247 (26,838) -------------- ------------- -------------- OTHER INCOME (EXPENSE) Interest expense......................................... (2,310) (2,893) (2,384) Gain on sales of property and equipment.................. 1,031 10,926 53 Other.................................................... 269 474 85 -------------- ------------- -------------- Total other income (expense)......................... (1,010) 8,507 (2,246) -------------- ------------- -------------- INCOME (LOSS) BEFORE INCOME TAXES............................. 30,530 10,754 (29,084) INCOME TAX EXPENSE............................................ 2,717 - - -------------- ------------- -------------- NET INCOME (LOSS)............................................. $ 27,813 $ 10,754 $ (29,084) ============== ============= ============= Net income (loss) per common share: Basic.................................................... $ 3.02 $ 1.19 $ (3.27) ============== ============= ============= Diluted.................................................. $ 2.91 $ 1.18 $ (3.27) ============== ============= ============= Weighted average common shares outstanding: Basic.................................................... 9,211 9,005 8,905 ============== ============= ============== Diluted.................................................. 9,543 9,148 8,905 ============== ============= ==============
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, 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 Issuance of stock through compensation plans .......... 86 8 1,839 -- -- 1,847 Net income ................... -- -- -- 27,813 -- 27,813 --------- --------- ----------- ---------- --------- ---------- BALANCE, December 31, 2000 .............. 9,254 $ 925 $ 72,529 $ 12,323 $ -- $ 85,777 ========= ========= =========== ========== ========= ==========
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, ------------------------------------ 2000 1999 1998 -------- -------- -------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) ................................ $ 27,813 $ 10,754 $(29,084) Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization ..... 27,794 20,810 31,665 Impairment of property and equipment ......... -- 81 8,493 Exploration costs ............................ 12,657 5,245 16,128 Gain on sales of property and equipment ...... (1,031) (10,926) (53) Deferred income taxes ........................ 2,717 -- -- Stock-based employee compensation ............ 937 -- -- Other ........................................ 399 274 375 Changes in operating working capital: Accounts receivable .......................... (6,579) (2,582) 2,842 Accounts payable ............................. 12,473 1,064 1,448 Other ........................................ (4,709) 18 1,691 -------- -------- -------- Net cash provided by operating activities 72,471 24,738 33,505 -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to property and equipment .............. (72,584) (19,683) (53,720) Proceeds from sales of property and equipment .... 1,075 19,060 260 Other ............................................ 3 (200) -- -------- -------- -------- Net cash used in investing activities ... (71,506) (823) (53,460) -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt ..................... -- -- 19,200 Repayments of long-term debt ..................... (500) (24,400) -- Proceeds from sale of common stock ............... 285 695 29 -------- -------- -------- Net cash provided by (used in) financing activities ............................ (215) (23,705) 19,229 -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ..................................... 750 210 (726) CASH AND CASH EQUIVALENTS Beginning of period .............................. 1,634 1,424 2,150 -------- -------- -------- End of period .................................... $ 2,384 $ 1,634 $ 1,424 ======== ======== ======== SUPPLEMENTAL DISCLOSURES Cash paid for interest, net of amounts capitalized .................................... $ 2,434 $ 3,021 $ 2,291 ======== ======== ========
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. 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 amounts reported in the financial statements and accompanying notes. 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 undivided interest in a limited partnership 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. Subsequent to December 31, 2000, the Company incurred approximately $3 million on one exploratory dry hole which was in progress at December 31, 2000. This amount will be charged to exploration expense during the first quarter of 2001. F-7 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NATURAL GAS AND OTHER PROPERTY AND EQUIPMENT Natural gas gathering and processing systems consist primarily of gas gathering pipelines, compressors and gas processing plants. Other property and equipment consists primarily of field equipment and facilities, office equipment, leasehold improvements and vehicles. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and any gain or loss is included in other income in the accompanying consolidated statements of operations. Depreciation of natural gas gathering and processing systems and other property and equipment is computed on the straight-line method over the estimated useful lives of the assets, which range from 3 to 39 years. VALUATION OF PROPERTY AND EQUIPMENT The Company follows the provisions of Statement of Financial Accounting Standards No. 121 "Accounting for Impairment of Long-Lived Assets" ("SFAS 121"), which requires that the Company's long-lived assets, including its oil and gas properties, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. SFAS 121 provides for future revenue from the Company's oil and gas production to be estimated 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. HEDGING ACTIVITIES From time to time, the Company utilizes fixed-price commodity swaps and collars (collectively "fixed-price contracts") to reduce its exposure to unfavorable changes in oil and natural gas prices. Since the Company's hedging objective is to optimize the price received for its oil and gas production, the Company generally enters into fixed-price contracts only when management of the Company believes that the quoted market prices for such commodities are likely to experience a sustained decline from then-current levels. Presently, the Company accounts for fixed-price contracts as hedging activities, and accordingly, records all realized gains and losses as oil and gas revenues in the period the hedged production is sold. However, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging F-8 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) Activities" ("SFAS 133"). See Note 10 for a discussion of the changes in accounting treatment for hedging activities that will result from the adoption of SFAS 133 in 2001. 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 the Company's inventory of unproved oil and gas properties are capitalized. During the years ended December 31, 2000, 1999 and 1998, the Company capitalized interest totaling approximately $483,000, $547,000 and $967,000, respectively. CASH AND CASH EQUIVALENTS The Company considers all cash and highly liquid investments with original maturities of three months or less to be cash equivalents. NET INCOME (LOSS) PER COMMON SHARE Basic earnings per share is computed by dividing net income by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if dilutive stock options were exercised, calculated using the treasury stock method. The diluted earnings per share calculations for the years ended December 31, 2000 and 1999 include an increase in potential shares attributable to dilutive stock options. Stock options were not considered in the diluted earnings per share calculations for 1998 as the effect would be 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") and related interpretations. 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, 2000, 1999 or 1998. 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, 2000, 1999 and 1998, the Company reported no differences between comprehensive income and net income. As a result of the adoption of SFAS 133 effective January 1, 2001, the Company will report a portion of the changes in market value of derivatives through other comprehensive income during 2001. CONCENTRATION OF CREDIT RISK The Company sells its oil and natural gas production to various customers, serves as operator in the drilling, completion and operation of oil and gas wells, and enters into fixed-price contracts with various counterparties. The Company obtains letters of credit to secure amounts due from its major oil and gas purchasers and follows other procedures to monitor credit risk from joint owners and fixed-contract counterparties. The Company has not experienced any significant credit losses since its F-9 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) inception. At December 31, 2000 and 1999, joint interest and other receivables are presented net of allowances for doubtful accounts of $350,000 and $150,000, respectively. 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, ------------------------------ 2000 1999 ------------- ------------- (IN THOUSANDS) Secured Bank Credit Facility (matures July 31, 2002)................ $ 30,000 $ 30,500 ============= =============
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. 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 in May and November, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company's oil and gas properties are pledged to secure advances under the credit facility. Effective January 1, 2001, the borrowing base established by the banks was increased from $50 million to $55 million, with no monthly commitment reductions. 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. Prior to July 1, 2000, Eurodollar Loans bore interest at the LIBOR rate plus a Eurodollar Margin ranging from 1.75% to 2.5% per annum. Effective July 1, 2000, the Eurodollar Margins were reduced by .5% and presently range from 1.25% to 2.0%. At December 31, 2000, the Company's indebtedness under the credit facility consisted of $30 million of Eurodollar Loans at a rate of 8.4%. 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, 2002. 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 and non-financial covenants at December 31, 2000. F-10 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 4. INCOME TAXES Prior to 2000, the Company's deferred tax assets exceeded its deferred tax liabilities due primarily to the existence of tax loss carryforwards available to offset future taxable income. Due to the uncertainty of realizing the related future benefits from such tax loss carryforwards, valuation allowances were recorded at each balance sheet date to the extent net deferred tax assets exceeded net deferred tax liabilities. During 2000, the Company's pre-tax income was sufficient to cause deferred tax liabilities to exceed deferred tax assets. Based upon current commodity prices and production volumes, as well as the availability of tax planning strategies (such as elective capitalization of intangible drilling costs), the Company presently believes that it is more likely than not that the Company will be able to utilize its cumulative tax loss carryforwards of $42.6 million before they expire (beginning in 2008). Accordingly, the Company reversed the valuation allowance provided at December 31, 1999 during the year ended December 31, 2000. Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. The Company's net deferred tax liabilities at December 31, 2000 are recorded as a current asset of $601,000 and a non-current liability of $2,159,000. Significant components of net deferred tax liabilities at December 31, 2000 and December 31, 1999 are as follows:
YEAR ENDED DECEMBER 31, --------------------------------------- 2000 1999 ----------------- ----------------- (IN THOUSANDS) Deferred tax assets: Tax loss carryforwards................................. $ 15,874 $ 12,961 Accrued stock-based compensation....................... 327 - Other.................................................. 897 956 ----------------- ----------------- 17,098 13,917 ----------------- ----------------- Deferred tax liabilities: Property and equipment................................. (18,656) (6,183) ----------------- ----------------- Valuation allowance........................................ - (7,734) ----------------- ----------------- Net deferred tax assets (liabilities)...................... $ (1,558) $ - ================= =================
F-11 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) All differences between the statutory income tax rates and the effective income tax rates for the years ended December 31, 1999 and 1998 were attributable to changes in valuation allowances. For the year ended December 31, 2000, the Company's effective income tax rate differed from the statutory federal income tax rate for the following reasons:
YEAR ENDED DECEMBER 31, 2000 ---------------------- (IN THOUSANDS) Income tax expense at statutory rate of 35%......................... $ 10,686 Change in valuation allowance....................................... (7,149) Tax depletion in excess of basis.................................... (965) Revision of previous tax estimates.................................. 114 Other............................................................... 31 --------------------- Income tax expense................................................ $ 2,717 ===================== Current............................................................. $ - Deferred............................................................ 2,717 --------------------- Income tax expense................................................ $ 2,717 =====================
The Company derives an income tax benefit when employees and directors exercise options granted under the Company's stock compensation plans (see Note 6). Employee stock options that are classified as fixed stock options under APB 25 do not result in a charge against book income when the option price is equal to or greater than the market price at date of grant. Therefore, any tax benefit from the exercise of fixed stock options results in a permanent difference, which is recorded to additional paid-in capital when the tax benefit is realized. At December 31, 1999, $585,000 of tax benefits related to the exercise of fixed stock options was fully reserved by a valuation allowance. During the current period, the valuation allowance was reversed, and additional tax benefits totaling $574,000 were realized. Accordingly, the Company credited additional paid-in capital during the year ended December 31, 2000 for $1,159,000 related to the exercise of employee stock options. 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. 6. STOCK COMPENSATION PLANS 1993 PLAN In September 2000, the Company's stockholders authorized an increase in the number of shares reserved for issuance under the 1993 Stock Compensation Plan ("1993 Plan") from 898,200 to 1,798,200. 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, 2000 expire 10 years from the date of grant and become exercisable based on varying vesting schedules. F-12 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The following table reflects activity in the 1993 Plan for 2000, 1999 and 1998.
2000 1999 1998 --------------------- --------------------- ---------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE SHARES PRICE SHARES PRICE SHARES PRICE Beginning of year 526,165 $ 9.03 722,052 $ 11.23 632,269 $ 10.99 Granted (a) . 2,059 $ 14.50 304,870 $ 5.50 110,168 $ 11.61 Exercised ... (59,499) $ 3.11 (188,200) $ 3.55 (12,305) $ 2.39 Forfeited ... (2,885) $ 5.50 (18,668) $ 10.85 (8,080) $ 11.69 Cancelled (b) -- -- (293,889) $ 14.15 -- -- --------- -------- -------- End of year ...... 465,840 $ 9.83 526,165 $ 9.03 722,052 $ 11.23 ========= ======== ======== Exercisable ...... 356,122 $ 11.11 254,204 $ 11.02 261,089 $ 7.72 ========= ======== ======== Issuable ......... 1,049,155 148,329 140,642 ========= ======== ========
-------------- (a) In addition to the reissuances described in Note (b), the Company granted new options as follows: 2000 - 2,059 shares at $14.50 per share; 1999 - 9,981 shares at $5.50 per share and 1,000 shares at $6.00 per share; and 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. (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 March 2000, the Financial Accounting Standards Board issued Interpretation No. 44 ("FIN 44") to APB 25 which required a change in the classification of 233,141 stock options repriced by the Company in April 1999 from fixed stock options to variable stock options. Pursuant to FIN 44, the Company is required to recognize compensation expense on the repriced options to the extent that the quoted market value of the Company's common stock at the end of each period after July 1, 2000 exceeds the amended option price ($5.50 per share), except that options vested as of July 1, 2000 must recognize compensation expense only to the extent that the quoted market value exceeds the market value on that date ($31.94 per share). The Company's closing market price at December 31, 2000 was $27.00. Accordingly, the Company made a non-cash provision for stock-based employee compensation of $937,000 for the six months ended December 31, 2000. As the repriced options are exercised, the cumulative amount of accrued compensation expense will be credited to additional paid-in capital. Since this provision is based on changes in the quoted market value of the Company's common stock, the Company's future results of operations may be subject to significant volatility. The following pro forma information, as required by Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"), presents net income and earnings per share information as if the stock options issued since December 31, 1994 were accounted for using the fair value method. The fair value of stock options issued for each year was estimated at the date of grant using the Black-Scholes option pricing model. Valuation assumptions for option grants in 2000, 1999 and 1998 included the following: risk-free interest rates of 5.5%, 5.5% and 5.2%; no dividends over the option term; stock price volatility factors of .74, .74 and .55, respectively, and a life expectancy of each option of seven years. F-13 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) The SFAS 123 pro forma information is as follows:
YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 1999 1998 ----------- ---------- ----------- Net income (loss).................................... $ 27,703 $ 9,613 $ (30,172) =========== ========== =========== Net income (loss) per diluted share.................. $ 2.90 $ 1.05 $ (3.39) =========== ========== ===========
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 24,000 shares of common stock (3,000 per year from 1993 through 2000) at option prices ranging from $3.25 to $18.50 per share. All options expire seven to 10 years from date of grant and are fully exercisable upon issuance. At December 31, 2000, options to purchase 13,000 shares were outstanding, and 62,300 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. At December 31, 2000, 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 2000, 1999 and 1998, the Company issued 11,811, 36,919 and 28,789 shares, respectively, of common stock to one officer in lieu of cash compensation aggregating $231,000, $264,000 and $278,000, respectively. The amounts of such compensation are included in general and administrative expense in the accompanying consolidated financial statements. 401(k) PLAN Employees who have met certain age and length of employment requirements are eligible to participate in a 401(k) plan sponsored by the Company. Participants may contribute up to 15% of pretax annual compensation to the plan, and the Company may, in its sole discretion, provide a matching contribution equal to a percentage of the participants' contributions. Participants become vested in the Company's contributions at a rate of 25% per year. The plan permits the Company to make its matching contributions in common stock of the Company. During 2000, 1999 and 1998, the Company contributed $189,000, $0, and $107,000, respectively, in market value of common stock to the 401(k) plan. 7. 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 $665,000, $788,000 and $664,000 for the years ended December 31, 2000, 1999 and 1998, respectively, and include charges to the Company by affiliates for rents and services aggregating $172,000, $259,000 and $102,000 for the years ended December 31, 2000, 1999 and 1998, respectively. The Company believes that all related party transactions are on terms no less favorable than those available from unrelated third parties. F-14 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 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. 8. 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 $400,000, $408,000 and $345,000 for the years ended December 31, 2000, 1999 and 1998, respectively. Future minimum payments under noncancelable leases at December 31, 2000, are as follows:
OPERATING LEASES ----------------- (IN THOUSANDS) 2001......................................................................... $ 687 2002......................................................................... 309 2003......................................................................... 163 Thereafter................................................................... 79 ------------------ Total minimum lease payments.......................................... $ 1,238 ==================
LEGAL PROCEEDINGS The Company is a defendant in a suit filed in October 1995 styled THE STATE OF TEXAS, ET AL V. UNION PACIFIC RESOURCES COMPANY ET AL, which case is 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. The Company is neither a common purchaser nor common carrier of oil. The plaintiffs have not undertaken any actions to prosecute this case since January 1996. Lead counsel for the plaintiffs withdrew from the case in 1996, and counsel for the individual named plaintiffs filed a Motion to Withdraw from the case in 1998. There has been no effort by the plaintiffs to have this case certified as a class since January 1996. 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. OTHER In November 1999, the Company guaranteed loans from a bank to certain employees of the Company, including one officer, in the aggregate amount of $834,000, the proceeds from which were used to finance the exercise of stock options granted under the 1993 Plan. During 2000, all employees other than the officer repaid their respective loans. The Company was contingently liable under this guarantee for $724,000 at December 31, 2000. F-15 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 9. FINANCIAL INSTRUMENTS At December 31, 2000, the Company was a party to certain fixed-price contracts, consisting of commodity swaps and collars, which had no carrying value in the accompanying consolidated balance sheet. Had these derivatives been recorded at their estimated fair market value, the Company would have reported a current liability of $376,000 at December 31, 2000. Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount due to the short maturity of those instruments. Long-term debt was estimated to have a fair value approximating the carrying amount since the stated interest rate is generally market sensitive. 10. DERIVATIVES DESCRIPTION OF CONTRACTS From time to time, the Company utilizes fixed-price contracts, consisting of swaps and collars, to reduce its exposure to unfavorable changes in oil and natural gas prices. Since the Company's hedging objective is to optimize the price received for its oil and natural gas production, the Company enters into fixed-price contracts only when management of the Company believes that the quoted market prices for such commodities are likely to experience a sustained decline from current levels. When using swaps to hedge oil and natural gas production, the Company receives a fixed price for the respective commodity and pays a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. Collars contain a fixed floor price (put) and ceiling price (call). If the market price for the respective commodity exceeds the call strike price or falls below the put strike price, then the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike prices, then no payments are due from either party. At December 31, 2000, the Company had open positions in the following fixed-price contracts: o Fixed-price oil swaps covering 34,000 barrels from April 2001 through October 2001 at an average price of $20.77 per barrel (ranging from a high of $21.55 in April 2001 to a low of $20.03 in October 2001). o Fixed-price oil collars covering 17,000 barrels 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. In addition, the Company had closed positions at December 31, 2000 in certain fixed-price oil swaps covering 687,000 barrels from January 2001 through December 2001 at an average price of $29.14 per barrel. These contracts were terminated in 2000 at an average price of $29.45 per barrel, resulting in an aggregate loss of $213,000. This loss was deferred at December 31, 2000 and will be recorded as a reduction in oil and gas revenues during the periods that correlate to the hedged production months. Subsequent to December 31, 2000, the Company entered into a fixed-price gas swap covering 940,000 MMBtu from February 2001 through April 2001 at an average price of $8.19 per MMBtu. The Company's position for February 2001 and March 2001 covering 650,000 MMBtu was terminated prior to maturity at an aggregate gain of $1.6 million. This gain will be recorded in oil and gas revenues during the periods that correlate to the hedged production months. In December 2000, the Company also entered into a speculative, fixed-price oil swap covering 10,000 barrels for the months of February 2001 and March 2001, whereby the Company agreed to pay an F-16 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) average fixed price of $26.02 and receive the floating price. This contract is deemed to be a speculative investment, not a hedging transaction. ACCOUNTING Through December 31, 2000, the Company has accounted for fixed-price contracts as hedging activities, and accordingly, has recorded the profit or loss from contract settlements as oil and gas revenues in the period the hedged production was sold. Included in oil and gas revenues are net losses totaling $1,121,000 in 2000 (comprised of losses of $1,711,000, partially offset by gains of $590,000), losses totaling $310,000 in 1999, and net gains totaling $9,871,000 in 1998 (comprised of gains of $10,024,000, partially offset by losses of $153,000). Effective January 1, 2001, the Company adopted SFAS 133 which established new accounting and reporting requirements for derivative instruments and hedging activities. SFAS 133 requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. The accounting for changes in the fair value of a derivative depends on both the intended purpose and the formal designation of the derivative. Designation is established at the inception of a derivative, but subsequent changes to the designation are permitted. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings, as is the time value component of fixed-price collars. Changes in fair value of derivative instruments which are not designated as cash flow hedges or do not meet the effectiveness guidelines of SFAS 133 are recorded in earnings as the changes occur. The Company designated the fixed-price oil swap covering 34,000 barrels as a cash flow hedge under SFAS 133, but elected not to designate any other derivatives at January 1, 2001 as cash flow hedges because of their relative short maturity or their terminated status. Upon adoption of SFAS 133 on January 1, 2001, the Company recorded a current liability of $376,000 attributable to the fair value of all fixed-price contracts held at that date, a credit to other comprehensive income of $83,000 (net of tax), an after-tax charge to earnings for the cumulative effect of an accounting change of $161,000, and a current asset of $132,000 related to the deferred tax benefit from the recorded loss. Most of the charge to earnings relates to the after-tax present value of the $213,000 deferred loss on early termination of a fixed-price oil swap. 11. IMPAIRMENT OF PROPERTY AND EQUIPMENT The Company has recorded provisions for impairment under SFAS 121 of $0, $81,000 and $8,493,000 for the years 2000, 1999 and 1998, 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 provision for 1999 was related to certain minor value properties. The Company has also recorded provisions for impairment of unproved properties aggregating $4.3 million, $4 million and $8.4 million in 2000, 1999 and 1998, respectively, and have charged such impairments to exploration costs in the accompanying statements of operations. F-17 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) 12. QUARTERLY FINANCIAL DATA (UNAUDITED) The following table summarizes results for each of the four quarters in the years ended December 31, 2000 and 1999.
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER YEAR ------- ------- ------- ------- ---- (IN THOUSANDS, EXCEPT PER SHARE) YEAR ENDED DECEMBER 31, 2000: Total revenues.......................... $ 20,221 $ 26,687 $ 32,086 $ 30,838 $ 109,832 Gross profit (a)........................ $ 15,652 $ 21,060 $ 25,106 $ 24,077 $ 85,895 Net income.............................. $ 6,424 $ 10,904 $ 8,351 $ 2,134 $ 27,813 Net income per common share (b): Basic............................... $ .70 $ 1.19 $ .90 $ .23 $ 3.02 Diluted............................. $ .69 $ 1.15 $ .87 $ .22 $ 2.91 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
------------------ (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. 13. 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, ---------------------------------------------------- 2000 1999 1998 -------------- -------------- --------------- (IN THOUSANDS) Property acquisitions: Proved................................. $ - $ - $ 7,077 Unproved............................... 11,131 3,221 10,602 Developmental costs........................... 36,510 8,199 7,285 Exploratory costs............................. 32,297 6,912 22,319 --------------- ---------------- --------------- Total.................................. $ 79,938 $ 18,332 $ 47,283 =============== ================ ===============
F-18 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, ------------------------------- 2000 1999 ------------- ------------- (IN THOUSANDS) Proved properties................................................... $ 481,348 $ 431,311 Unproved properties................................................. 20,194 5,520 ------------- ------------- Total capitalized costs............................................. 501,542 436,831 Accumulated depreciation, depletion and amortization...................................................... (372,163) (347,970) ------------- ------------- Net capitalized costs........................................ $ 129,379 $ 88,861 ============= =============
14. 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, --------------------------------------------------------------------------------------- 2000 1999 1998 -------------------------- ---------------------- ------------------------- OIL (A) GAS MBOE OIL GAS MBOE OIL GAS MBOE Proved reserves Beginning of period ............. 11,904 30,141 16,928 5,741 38,854 12,217 8,410 32,861 13,887 Revisions (b) ................... 770 (2,406) 369 5,077 663 5,188 (744) (3,248) (1,285) Extensions and discoveries ...... 2,623 8,620 4,059 3,239 9,306 4,790 254 8,768 1,716 Sales of minerals-in-place ...... -- -- -- (277) (13,835) (2,583) -- -- -- Purchases of minerals-in-place .. -- -- -- -- -- -- 349 5,306 1,233 Production ...................... (2,386) (8,047) (3,727) (1,876) (4,847) (2,684) (2,528) (4,833) (3,334) ------ ------ ------ ------ ------ ------ ----- ------ ------ End of period ................... 12,911 28,308 17,629 11,904 30,141 16,928 5,741 38,854 12,217 ====== ====== ====== ====== ====== ====== ===== ====== ====== Proved developed reserves Beginning of period ............. 9,028 26,960 13,521 5,504 32,215 10,873 7,826 27,392 12,392 ====== ====== ====== ===== ====== ====== ===== ====== ====== End of period ................... 10,565 26,278 14,945 9,028 26,960 13,521 5,504 32,215 10,873 ====== ====== ====== ===== ====== ====== ===== ====== ======
------------ (a) Revisions and ending balance for 2000 include natural gas liquids. (b) Effective December 31, 2000, the Company changed its method of estimating future natural gas production from a wet stream to a dry stream. This change resulted in an increase in natural gas liquids of 1,262 MBOE, a decrease in natural gas of 3,976 MMcf and an increase in oil equivalents of 599 MBOE. F-19 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, ---------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (IN THOUSANDS) Future cash inflows .................................... $ 609,867 $ 369,584 $ 128,149 Future costs: Production ...................................... (135,919) (76,507) (43,647) Development ..................................... (27,336) (24,861) (9,999) Income taxes .................................... (118,534) (56,959) -- --------- --------- --------- Future net cash flows .................................. 328,078 211,257 74,503 10% discount factor .................................... (96,014) (59,615) (22,442) --------- --------- --------- Standardized measure of discounted future net cash flows $ 232,064 $ 151,642 $ 52,061 ========= ========= =========
Changes in the standardized measure of discounted future net cash flows relating to proved reserves were as follows:
YEAR ENDED DECEMBER 31, ---------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (IN THOUSANDS) Standardized measure, beginning of period ............. $ 151,642 $ 52,061 $ 92,403 Net changes in sales prices, net of production costs .. 95,305 63,593 (31,210) Revisions of quantity estimates ....................... 6,289 58,821 (6,103) Accretion of discount ................................. 17,650 5,206 9,992 Changes in future development costs, including development costs incurred that reduced future development costs .................................... 7,007 1,850 8,415 Changes in timing and other ........................... 12,924 (7,348) (2,758) Net change in income taxes ............................ (50,533) (24,858) 7,515 Extensions and discoveries ............................ 83,266 46,892 7,165 Sales, net of production costs ........................ (91,486) (33,144) (37,695) Sales of minerals-in-place ............................ -- (11,431) -- Purchases of minerals-in-place ........................ -- -- 4,337 --------- --------- --------- Standardized measure, end of period ................... $ 232,064 $ 151,642 $ 52,061 ========= ========= =========
F-20 INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION OF EXHIBIT -------- ------------------------------------------------------------------------------------------------------- 21. Subsidiaries of the Registrant 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