-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Nnvv6E70gJQiuBDqQQ3xgRhYDD1Ji/xiG/rDpuRkFCsdLWMkhBZWmd08KUcMN4li 3HrV3TFagmcyuvdR2nLHfg== 0000912057-99-005264.txt : 19991115 0000912057-99-005264.hdr.sgml : 19991115 ACCESSION NUMBER: 0000912057-99-005264 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CLAYTON WILLIAMS ENERGY INC /DE CENTRAL INDEX KEY: 0000880115 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752396863 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-10924 FILM NUMBER: 99749352 BUSINESS ADDRESS: STREET 1: SIX DESTA DR STE 3000 CITY: MIDLAND STATE: TX ZIP: 79705 BUSINESS PHONE: 9156826324 MAIL ADDRESS: STREET 1: SIX DESTA DRIVE STREET 2: STE 3000 CITY: MIDLAND STATE: TX ZIP: 79705 10-Q 1 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q /XX/ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999 or / / Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ______to ______ COMMISSION FILE NO. 0-20838 CLAYTON WILLIAMS ENERGY, INC. -------------------------------------------------------- (Exact name of Registrant as specified in its charter) DELAWARE 75-2396863 -------------------- ----------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 6 DESTA DRIVE, SUITE 6500, MIDLAND, TEXAS 79705-5510 ----------------------------------------- ---------------- (Address of principal executive offices) (Zip code) Registrant's Telephone Number, including area code: (915) 682-6324 Not applicable ----------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES /XX/ NO / / NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF NOVEMBER 9, 1999.....9,106,631. CLAYTON WILLIAMS ENERGY, INC. TABLE OF CONTENTS PART I. FINANCIAL INFORMATION
Page ---- ITEM 1. FINANCIAL STATEMENTS Consolidated Balance Sheets as of September 30, 1999 and December 31, 1998........................................................... 3 Consolidated Statements of Operations for the three months and nine months ended September 30, 1999 and 1998....................................... 4 Consolidated Statements of Cash Flows for the nine months ended September 30, 1999 and 1998............................................... 5 Notes to Consolidated Financial Statements........................................ 6 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............................................. 9 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS........................ 17 PART II. OTHER INFORMATION ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.................................................. 19
2 CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS)
ASSETS SEPTEMBER 30, DECEMBER 31, 1999 1998 --------------- --------------- (UNAUDITED) CURRENT ASSETS Cash and cash equivalents............................................. $ 5,347 $ 1,424 Accounts receivable: Trade, net.......................................................... 1,724 6,782 Affiliates.......................................................... 1,042 244 Oil and gas sales................................................... 8,503 3,628 Inventory............................................................. 896 1,230 Property held for resale.............................................. - 7,521 Other................................................................. 343 482 --------------- --------------- 17,855 21,311 --------------- --------------- PROPERTY AND EQUIPMENT Oil and gas properties, successful efforts method..................... 430,996 424,360 Natural gas gathering and processing systems.......................... 9,851 8,292 Other................................................................. 10,174 10,480 --------------- --------------- 451,021 443,132 Less accumulated depreciation, depletion and amortization............. (359,088) (343,857) --------------- --------------- Property and equipment, net......................................... 91,933 99,275 --------------- --------------- OTHER ASSETS............................................................. 60 67 --------------- --------------- $ 109,848 $ 120,653 ================ ================ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable: Trade............................................................... $ 9,045 $ 16,384 Affiliates.......................................................... 54 65 Oil and gas sales................................................... 6,538 3,433 Current maturities of long-term debt.................................. 7,800 15,800 Accrued liabilities and other......................................... 882 1,477 --------------- --------------- 24,319 37,159 --------------- --------------- LONG-TERM DEBT........................................................... 31,200 39,100 --------------- --------------- STOCKHOLDERS' EQUITY Preferred stock, par value $.10 per share; authorized - 3,000,000 shares; issued and outstanding - none................................ - - Common stock, par value $.10 per share; authorized - 15,000,000 shares; issued - 8,991,437 shares in 1999 and 8,937,561 shares in 1998....................................................... 899 894 Additional paid-in capital............................................ 70,015 69,744 Retained deficit...................................................... (16,585) (26,244) --------------- --------------- 54,329 44,394 --------------- --------------- $ 109,848 $ 120,653 ================ ================
The accompanying notes are an integral part of these consolidated financial statements. 3 CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (IN THOUSANDS, EXCEPT PER SHARE)
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------------------- ------------------------------- 1999 1998 1999 1998 ------------- -------------- ------------- -------------- REVENUES Oil and gas sales........................... $ 12,675 $ 11,479 $ 30,105 $ 42,044 Natural gas services........................ 1,061 905 2,737 2,953 ------------- -------------- ------------- -------------- Total revenues............................ 13,736 12,384 32,842 44,997 ------------- -------------- ------------- -------------- COSTS AND EXPENSES Lease operations............................ 2,898 3,251 8,286 10,903 Exploration: Abandonments and impairments.............. 1,237 1,760 2,131 7,236 Seismic and other......................... 451 823 828 2,872 Natural gas services........................ 857 806 2,313 2,515 Depreciation, depletion and amortization.... 5,081 6,881 15,921 24,707 General and administrative.................. 703 868 2,574 3,040 ------------- -------------- ------------- -------------- Total costs and expenses.................. 11,227 14,389 32,053 51,273 ------------- -------------- ------------- -------------- Operating income (loss)................... 2,509 (2,005) 789 (6,276) ------------- -------------- ------------- -------------- OTHER INCOME (EXPENSE) Interest expense............................ (685) (554) (2,162) (1,539) Gain on sales of property and equipment..... 21 20 10,614 33 Other....................................... 51 114 418 123 ------------- -------------- ------------- -------------- Total other income (expense).............. (613) (420) 8,870 (1,383) ------------- -------------- ------------- -------------- INCOME (LOSS) BEFORE INCOME TAXES.............. 1,896 (2,425) 9,659 (7,659) INCOME TAX EXPENSE............................. - - - - ------------- -------------- ------------- -------------- NET INCOME (LOSS).............................. $ 1,896 $ (2,425) $ 9,659 $ (7,659) ============= ============== ============= ============== Net income (loss) per common share: Basic....................................... $ .21 $ (.27) $ 1.08 $ (.86) ============= ============== ============= ============== Diluted..................................... $ .20 $ (.27) $ 1.05 $ (.86) ============= ============== ============= ============== Weighted average common shares outstanding: Basic....................................... 8,986 8,907 8,971 8,897 ============= ============== ============= ============== Diluted..................................... 9,288 8,907 9,171 8,897 ============= ============== ============= ==============
The accompanying notes are an integral part of these consolidated financial statements. 4 CLAYTON WILLIAMS ENERGY, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------ 1999 1998 ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss).......................................................... $ 9,659 $ (7,659) Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization............................... 15,921 24,707 Exploration costs...................................................... 2,131 7,236 Gain on sales of property and equipment................................ (10,614) (33) Other.................................................................. 204 269 Changes in operating working capital: Accounts receivable.................................................... (615) 5,012 Accounts payable....................................................... (1,574) (1,642) Other.................................................................. (115) 856 ------------- ------------- Net cash provided by operating activities......................... 14,997 28,746 ------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to property and equipment........................................ (13,732) (38,170) Proceeds from sales of property and equipment.............................. 18,486 79 ------------- ------------- Net cash provided by (used in) investing activities............... 4,754 (38,091) ------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt............................................... - 9,600 Repayments of long-term debt............................................... (15,900) - Proceeds from sale of common stock......................................... 72 7 ------------- ------------- Net cash provided by (used in) financing activities............... (15,828) 9,607 ------------- ------------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............................ 3,923 262 CASH AND CASH EQUIVALENTS Beginning of period........................................................ 1,424 2,150 ------------- ------------- End of period.............................................................. $ 5,347 $ 2,412 ============= ============= SUPPLEMENTAL DISCLOSURES Cash paid for interest, net of amounts capitalized......................... $ 2,264 $ 1,496 ============= =============
The accompanying notes are an integral part of these consolidated financial statements. 5 CLAYTON WILLIAMS ENERGY, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SEPTEMBER 30, 1999 (UNAUDITED) 1. NATURE OF OPERATIONS Clayton Williams Energy, Inc. and its subsidiaries (collectively, the "Company") is an independent oil and gas company engaged in the exploration for and development and production of oil and natural gas primarily in South and East Texas, the Texas Gulf Coast, Louisiana, Southeastern New Mexico and Mississippi. Substantially all of the Company's oil and gas production is sold under short-term contracts which are market-sensitive. Accordingly, the Company's financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. From time to time, the Company utilizes hedging transactions with respect to a portion of its oil and gas production to mitigate its exposure to price fluctuations (see Note 5). 2. PRESENTATION The preparation of these consolidated financial statements in conformity with generally accepted accounting principles requires management of the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the opinion of management, the Company's unaudited consolidated financial statements as of September 30, 1999 and for the interim periods ended September 30, 1999 and 1998 include all adjustments, consisting only of normal recurring accruals, which are necessary for a fair presentation in accordance with generally accepted accounting principles. These interim results are not necessarily indicative of the results to be expected for the year ending December 31, 1999. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company's 1998 Form 10-K. 3. LONG-TERM DEBT Long-term debt consists of the following:
SEPTEMBER 30, DECEMBER 31, 1999 1998 --------------- --------------- (IN THOUSANDS) Secured Bank Credit Facility (matures July 31, 2001).............. $ 39,000 $ 54,900 Less current maturities........................................... (7,800) (15,800) --------------- -------------- $ 31,200 $ 39,100 =============== ==============
6 The Company's secured bank credit facility (the "Credit Facility") provides for a revolving loan facility in an amount not to exceed the lesser of the borrowing base, as established by the banks, or that portion of the borrowing base determined by the Company to be the elected borrowing limit. The borrowing base, which is based on the discounted present value of future net revenues from oil and gas production, is subject to redetermination at any time, but at least semi-annually, and is made at the discretion of the banks. If, at any time, the redetermined borrowing base is less than the amount of outstanding indebtedness, the Company will be required to (i) pledge additional collateral, (ii) prepay the excess in not more than five equal monthly installments, or (iii) elect to convert the entire amount of outstanding indebtedness to a term obligation based on amortization formulas set forth in the loan agreement. Substantially all of the Company's oil and gas properties are pledged to secure advances under the Credit Facility. As of September 30, 1999, the borrowing base established by the banks was $41.05 million and requires monthly commitment reductions of $650,000. The Company has requested an increase in the borrowing base, and the banks are presently evaluating the underlying oil and gas reserves in order to establish a new borrowing base to be effective on or before November 30, 1999. All outstanding balances on the Credit Facility may be designated, at the Company's option, as either "Base Rate Loans" or "Eurodollar Loans" (as defined in the loan agreement), provided that not more than two Eurodollar traunches may be outstanding at any time. Base Rate Loans bear interest at the fluctuating Base Rate plus a Base Rate Margin ranging from 0% to 3/8% per annum, depending on levels of outstanding advances and letters of credit. Eurodollar Loans bear interest at the LIBOR rate plus a Eurodollar Margin ranging from 1.75% to 2.5% per annum. At September 30, 1999, the Company's indebtedness under the Credit Facility consisted of $39 million of Eurodollar Loans at a rate of 7.9%. In addition, the Company pays the banks a commitment fee equal to 1/4% per annum on the unused portion of the revolving loan commitment. Interest on the revolving loan and commitment fees are payable quarterly, and all outstanding principal and interest will be due July 31, 2001. The loan agreement contains financial covenants that are computed quarterly and require the Company to maintain minimum levels of working capital, cash flow and net tangible assets. The Company was in compliance with all of the financial covenants at September 30, 1999. 4. STOCK COMPENSATION PLANS In May 1995, the Company's Board of Directors adopted the Executive Incentive Stock Compensation Plan, permitting the Company to pay all or part of selected executives' salaries in shares of common stock in lieu of cash. The Company reserved 500,000 shares of common stock for issuance under this plan. During the nine months ended September 30, 1999, the Company issued 31,715 shares of common stock to one officer in lieu of cash compensation aggregating $193,708. Subsequent to September 30, 1999, the Company issued an additional 3,631 shares to the same officer in lieu of cash compensation aggregating $46,802. The amounts of such compensation are included in general and administrative expense in the accompanying consolidated financial statements. 5. FORWARD SALE TRANSACTIONS From time to time, the Company utilizes forward sale and other financial option arrangements, such as swaps and collars, to reduce price risks on the sale of its oil and gas production. The Company accounts for such arrangements as hedging activities and, accordingly, records all realized gains and losses as oil and gas revenues in the period the hedged production is sold. Included in oil and gas revenues during the nine month periods ended September 30, 1999 and 1998 are losses totaling $309,000 and net gains totaling $7,228,000 (comprised of gains of $7,381,000, partially offset by losses of $153,000), respectively. 7 6. PROPERTY SALES In January 1999, the Company completed the sale of its interests in eight non-operated oil and gas wells located in Matagorda County, Texas for $5.2 million resulting in a gain of $1.8 million. In April 1999, the Company also sold its interests in the Jalmat Field located in Lea County, New Mexico for $12.5 million and recorded a gain of $8.3 million. 7. INCOME TAXES No provisions for income tax expense were required during the periods presented since the Company has net operating loss carryforwards available to offset any taxable income generated during such periods. Due to the uncertainty of realizing the related future benefits from these tax loss carryforwards, valuation allowances were recorded at September 30, 1999 and 1998 to the extent net deferred tax assets exceed net deferred tax liabilities. 8. RECENT ACCOUNTING PRONOUNCEMENT In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments and hedging activities. It requires that derivatives be recognized as assets or liabilities and measured at their fair value. SFAS 133 will be adopted in 2001 and is not expected to have a material effect on the Company's financial condition or operations. 8 ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Certain statements in this Form 10-Q constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that Clayton Williams Energy, Inc. and its subsidiaries (the "Company") expects, projects, believes or anticipates will or may occur in the future, including such matters as oil and gas reserves, future drilling and operations, future production of oil and gas, future net cash flows, future capital expenditures and other such matters, are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors which may cause the actual results, performance, or achievements of the Company to be materially different from any future results, performance, or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: the volatility of oil and gas prices, the Company's drilling results, the Company's ability to replace short-lived reserves, the availability of capital resources, the reliance upon estimates of proved reserves, operating hazards and uninsured risks, competition, government regulation, the ability of the Company to implement its business strategy, and other factors referenced in this Form 10-Q. The following discussion is intended to assist in understanding the Company's historical consolidated financial position at September 30, 1999 and results of operations and cash flows for the periods ended September 30, 1999 and 1998. This discussion should be read in conjunction with the Company's Form 10-K for the year ended December 31, 1998 and the consolidated financial statements and notes thereto included in this Form 10-Q. OVERVIEW Prior to 1998, the Company and its predecessors concentrated their drilling activities in the Cretaceous Trend (the "Trend") which extends from South Texas through East Texas, Louisiana and other southern states and includes the Austin Chalk, Buda and Georgetown formations. Oil and gas production in the Trend is generally characterized by a high initial production rate, followed by a steep rate of decline. In order to maintain its oil and gas reserve base, production levels and cash flow from operations, the Company is required to maintain or increase its level of drilling activity and achieve comparable or improved results from such activities. However, weak product prices caused the Company to suspend its Trend drilling activities in April 1998. In response to recent improvements in oil and gas prices, the Company initiated a water frac program in June 1999 in an attempt to accelerate its Trend oil production. The Company has conducted cyclic water stimulation treatments on 15 wells to date, and plans to stimulate approximately 16 other Austin Chalk wells by the end of the first quarter of 2000. Daily production rates from the first 12 completed stimulations have increased by an average of approximately 100 barrels of oil per day over pre-stimulation levels. The Company is also currently drilling two horizontal Austin Chalk wells in the Trend, and anticipates drilling additional horizontal wells in this area on a well-by-well basis for the remainder of 1999. Beginning in 1997, the Company initiated several exploratory projects designed to reduce its dependence on Trend drilling for future production and reserve growth. These new areas include other formations in the vicinity of its core properties in east central Texas, as well as South Texas, Louisiana and Mississippi, and emphasize the development of long-life gas reserves. During 1998, the Company devoted a substantial portion of its capital expenditures to these new areas. Except for its Cotton Valley Pinnacle Reef play and certain other prospects in Louisiana, the Company has no present plans to incur any significant capital expenditures in these new areas in 1999 (see "LIQUIDITY AND CAPITAL RESOURCES - CAPITAL EXPENDITURES"). However, the Company may farmout to industry partners its position on prospects where exploratory drilling is warranted and attempt to retain a carried interest in any wells drilled. In late May 1999, the Company began selling gas from the J. C. Fazzino Unit #1, a Cotton Valley Pinnacle Reef discovery in Robertson County, Texas. To date, the well has produced approximately 1 Bcf of gas, net to the Company's interest. 9 Based upon data obtained during post-completion operations, the Company determined that the Fazzino #1 penetrated the edge of the reef. As a result, the Company drilled the J. C. Fazzino Unit #2 in an effort to penetrate the core of the reef. To date, the Company has treated approximately 550 feet of the reef and has seen encouraging gas flow rates. The Company plans to perforate and stimulate the final section of the reef in November 1999, and then place the well on production. Approximately 67% of the estimated $6.5 million cost to drill and complete the Fazzino #2 is being financed through a non-recourse vendor financing arrangement which permits the Company to pay participating vendors for services and materials out of a dedicated percentage of revenues from the well. During 1998 and continuing throughout the first quarter of 1999, the oil and gas industry operated in a depressed commodity price environment. Anticipating the adverse effects that low product prices could have on its capital resources, the Company initiated efforts late in 1998 to sell its interests in two properties in order to reduce the amount of outstanding indebtedness on the Credit Facility. In January 1999, the Company sold its interests in eight non-operated oil and gas wells located in Matagorda County, Texas for $5.2 million, and sold its interests in the Jalmat Field located in Lea County, New Mexico for $12.5 million in April 1999. In the aggregate, these properties accounted for approximately 9% of the Company's 1998 annual oil and gas production on a BOE basis and 22% of the Company's estimated future net revenues (discounted at 10%) at December 31, 1998. A significant portion of the Company's capital expenditures during 1998 and the first nine months of 1999 have been spent on acquisitions of exploratory acreage, exploratory wells with limited production history, and exploratory wells which have resulted in dry holes. Accordingly, production from wells drilled subsequent to September 30, 1998 has not been sufficient to offset the recent declines in oil and gas production attributable to the temporary suspension of Trend drilling and the sales of producing properties. Furthermore, until these new projects are completed and establish commercial levels of production, there can be no assurance that the Company will be successful in its efforts to replace such production declines. The Company follows the successful efforts method of accounting for its oil and gas properties, whereby costs of productive wells, developmental dry holes and productive leases are capitalized and amortized using the unit-of-production method based on estimated proved reserves. Costs of unproved properties are initially capitalized. Those properties with significant acquisition costs are periodically assessed, and any impairment in value is charged to expense. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate groups based on the Company's historical experience, acquisition dates and average lease terms. Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to expense if and when the well is determined to be unsuccessful. 10 RESULTS OF OPERATIONS The following table sets forth certain operating information of the Company for the periods presented:
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, --------------------------- --------------------------- 1999 1998 1999 1998 ----------- ----------- ------------ ----------- OIL AND GAS PRODUCTION DATA: Oil (MBbls)............................ 449 570 1,398 2,066 Gas (MMcf)............................. 1,158 1,250 3,268 3,671 MBOE (1)............................... 642 778 1,943 2,678 AVERAGE OIL AND GAS SALES PRICES (2): Oil ($/Bbl)............................ $ 20.23 $ 15.32 $ 15.67 $ 16.34 Gas ($/Mcf)............................ $ 2.88 $ 2.35 $ 2.33 $ 2.38 OIL AND GAS COSTS ($/BOE PRODUCED): Lease operating expenses............... $ 4.51 $ 4.18 $ 4.26 $ 4.07 Oil and gas depletion.................. $ 7.51 $ 8.59 $ 7.90 $ 8.96 NET WELLS DRILLED (3): Exploratory Wells...................... .6 2.7 2.1 5.2 Developmental Wells.................... - - - 4.4
- ------------- (1) Gas is converted to barrel of oil equivalents (BOE) at the ratio of six Mcf of gas to one Bbl of oil. (2) Includes effects of hedging transactions. (3) Excludes wells being drilled or completed at the end of each period. THREE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO SEPTEMBER 30, 1998 REVENUES Oil and gas sales increased 10% from $11.5 million in 1998 to $12.7 million in 1999 due primarily to significant increases in oil and gas prices, offset in part by a 21% decline in oil production and a 7% decline in gas production. The decline in oil production was caused primarily by the suspension of horizontal drilling activities in the Trend from April 1998 to October 1999 in response to unfavorable oil prices. Gas production declined due primarily to the loss of production from two gas properties sold in 1999, offset in part by new production from the Cotton Valley Pinnacle Reef area. Since the Fazzino #2 well is still in the completion and testing phase of operations, and since the Company has just recently resumed development activities in the Trend, production from drilling and completion activities subsequent to September 30, 1998 has not been sufficient to offset the decline in oil and gas production attributable to the suspension of Trend drilling and the sales of producing properties. Furthermore, until these wells and other exploratory projects establish and sustain commercial levels of production, there can be no assurance that the Company will be successful in its efforts to offset the decline in production. The Company's average price per barrel of oil increased 32% after giving effect to a $3.54 per barrel gain on hedging activities in the 1998 period. Average gas prices increased 23% after giving effect to a $.21 per Mcf gain in the 1998 period. COSTS AND EXPENSES Lease operations expenses decreased 12% from $3.3 million in 1998 to $2.9 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 17% during the current quarter, causing an 8% increase in lease operations expenses on a BOE basis from $4.18 per BOE in 1998 to $4.51 per BOE in 1999. 11 Exploration costs decreased 35% from $2.6 million in 1998 to $1.7 million in 1999 due primarily to substantially lower dry hole costs and seismic costs in the 1999 period as compared to the 1998 period. Because the Company follows the successful efforts method of accounting, the Company's results of operations may be adversely affected during any accounting period in which seismic costs, exploratory dry hole costs, and unproved property impairments are expensed. Depreciation, depletion and amortization expense decreased 26% from $6.9 million in 1998 to $5.1 million in 1999 due primarily to a 17% decrease in oil and gas production on a BOE basis during the 1999 quarter and, to a lesser extent, to a 13% decline in the average depletion rate. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The decline in the average depletion rate per BOE from $8.59 in 1998 to $7.51 in 1999 was primarily due to higher reserve estimates attributable to improved product prices. General and administrative expenses declined 19% from $868,000 in 1998 to $703,000 in 1999. Beginning in December 1998, the Company implemented certain cost reduction measures, consisting primarily of personnel layoffs and salary reductions, in order to reduce overhead and conserve financial resources. The effects of these efforts were offset in part by the loss of certain overhead reimbursements associated with the sale of the Company's interests in the Jalmat Field in April 1999. INTEREST EXPENSE AND OTHER Interest expense increased 24% from $554,000 in 1998 to $685,000 in 1999 due primarily to a decrease in capitalized interest from $333,000 in the 1998 period to $145,000 in the 1999 period. Gross interest expense (before capitalization) decreased slightly due primarily to lower average levels of indebtedness on the Credit Facility. The average daily principal balance outstanding on such facility during the third quarter of 1999 was $39.7 million compared to $41.9 million in 1998. The effective annual interest rate on bank debt, including bank fees, during the 1999 quarter was 8.2%, which was comparable to the 1998 rate. NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO SEPTEMBER 30, 1998 REVENUES Oil and gas sales decreased 28% from $42 million in 1998 to $30.1 million in 1999 due primarily to lower oil and gas production and, to a lesser extent, lower oil and gas prices. The 32% decline in oil production was caused primarily by the suspension of horizontal drilling activities in the Trend from April 1998 to October 1999 in response to unfavorable oil prices. Gas production declined 11% due primarily to the loss of production from two gas properties sold in 1999, offset in part by new production from the Cotton Valley Pinnacle Reef area. Since the Fazzino #2 well is still in the completion and testing phase of operations, and since the Company has just recently resumed development activities in the Trend, production from drilling and completion activities subsequent to September 30, 1998 has not been sufficient to offset the recent declines in oil and gas production attributable to the suspension of Trend drilling and the sales of producing properties. Furthermore, until these wells and other exploratory projects establish and sustain commercial levels of production, there can be no assurance that the Company will be successful in its efforts to offset the decline in production. The Company's average price per barrel of oil declined 4% after giving effect to a $.14 per barrel loss on hedging activities in the 1999 period as compared to a $3.26 per barrel gain in the 1998 period. Average gas prices also declined 2% after giving effect to a $.03 per Mcf hedging loss in the 1999 period as compared to a $.16 per Mcf gain in the 1998 period. 12 COSTS AND EXPENSES Lease operations expenses decreased 24% from $10.9 million in 1998 to $8.3 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 27% during the current period, causing a 5% increase in lease operations expenses on a BOE basis from $4.07 per BOE in 1998 to $4.26 per BOE in 1999. Exploration costs decreased 70% from $10.1 million in 1998 to $3 million in 1999 due primarily to a combination of substantially lower dry hole costs, impairments of unproved properties and seismic costs. Because the Company follows the successful efforts method of accounting, the Company's results of operations may be adversely affected during any accounting period in which seismic costs, exploratory dry hole costs, and unproved property impairments are expensed. Depreciation, depletion and amortization expense decreased 36% from $24.7 million in 1998 to $15.9 million in 1999 due primarily to a 27% decrease in oil and gas production on a BOE basis during the 1999 period and, to a lesser extent, to a 12% decline in the average depletion rate. Under the successful efforts method of accounting, costs of oil and gas properties are amortized on a unit-of-production method based on estimated proved reserves. The decline in the average depletion rate per BOE from $8.96 in 1998 to $7.90 in 1999 was primarily due to higher reserve estimates during the second and third quarter of 1999 attributable to improved product prices. General and administrative expenses decreased 13% from $3 million in 1998 to $2.6 million in 1999. Beginning in December 1998, the Company implemented certain cost reduction measures, consisting primarily of personnel layoffs and salary reductions, in order to reduce overhead and conserve financial resources. The effects of these efforts were offset in part by the loss of certain overhead reimbursements associated with the sale of the Company's interests in the Jalmat Field in April 1999. INTEREST EXPENSE AND OTHER Interest expense increased 47% from $1.5 million in 1998 to $2.2 million in 1999 due primarily to a combination of higher average levels of indebtedness on the Credit Facility and a decrease in capitalized interest from $817,000 in the 1998 period to $447,000 in the 1999 period. The average daily principal balance outstanding on the Credit Facility during the 1999 period was $44.3 million compared to $37.7 million in 1998. The effective annual interest rate on bank debt, including bank fees, during 1999 was 7.8% compared to 8.2% in 1998. During 1999, the Company recorded gains on sales of property and equipment of $10.6 million, which included a gain of $8.3 million on the sale of the Company's interest in the Jalmat Field located in Lea County, New Mexico for $12.5 million, and a gain of $1.8 million on the sale of the Company's interest in eight non-operated gas wells in Matagorda County, Texas for $5.2 million. 13 LIQUIDITY AND CAPITAL RESOURCES OVERVIEW The Company's primary financial resource is its oil and gas reserves. In accordance with the terms of the Credit Facility, the banks establish a borrowing base, as derived from the estimated value of the Company's oil and gas properties, against which the Company may borrow funds as needed to supplement its internally generated cash flow as a source of financing for its capital expenditure program. Product prices, over which the Company has very limited control, have a significant impact on such estimated value and thereby on the Company's borrowing availability under the Credit Facility. Within the confines of product pricing, the Company must be able to find and develop or acquire oil and gas reserves in a cost effective manner in order to generate sufficient financial resources through internal means to complete the financing of its capital expenditure program. In March 1999, the banks established the Credit Facility borrowing base at $53 million and provided for an automatic reduction of the borrowing base to $43 million upon sale of the Company's interests in the Jalmat Field located in Lea County, New Mexico and further provided for monthly commitment reductions of $650,000 beginning in July 1999. In April 1999, the Company repaid $11.5 million of indebtedness on the Credit Facility with proceeds from the Jalmat sale. Although the Company had approximately $2 million available on the Credit Facility at September 30, 1999, the monthly commitment reductions of $650,000 will reduce the borrowing base to $39.8 million at November 30, 1999. The Company has requested an increase in the borrowing base, and the banks are presently evaluating the underlying oil and gas reserves in order to establish a new borrowing base to be effective on or before November 30, 1999. Depending on the amount of the adjusted borrowing base, the Company may be required to finance a significant portion of its remaining capital expenditures for 1999 out of internally generated cash flow. The following discussion sets forth the Company's current plans for capital expenditures in 1999, and the expected capital resources needed to finance such plans. CAPITAL EXPENDITURES During the third quarter of 1999, the Company increased the amount it plans to spend in 1999 on exploration and development activities from $16.9 million to $21.3 million, of which $11.4 million has been incurred through September 30, 1999. Approximately 50% of the increase relates to additional activities in the Company's Cotton Valley Pinnacle Reef play, and approximately 25% is attributable to the generation of certain exploratory prospects in Louisiana. In response to improving product prices, the Company has initiated a water frac program in an attempt to accelerate its Trend oil production. To date, the Company has conducted cyclic water stimulations on 15 wells and plans to stimulate approximately 8 additional wells during the remainder of 1999. In addition, the Company is currently drilling two horizontal Austin Chalk wells and anticipates drilling additional horizontal wells in this area on a well-by-well basis for the remainder of 1999. In the aggregate, the Company plans to spend approximately $8 million on Trend development and leasing activities, of which $3 million has been incurred through September 30, 1999. The Company also plans to spend approximately $7.8 million on exploration and leasing activities on the Cotton Valley Exploratory Project in the North Giddings Field, of which $5.5 million has been incurred through September 30, 1999. The Company has drilled two wells on one of several Cotton Valley Pinnacle Reef anomalies identified by a 3-D seismic survey conducted in this area in 1997. The J. C. Fazzino Unit #1 was completed in March 1999, and the J. C. Fazzino Unit #2 is currently being completed. The Fazzino #2 is being drilled and completed pursuant to a non-recourse vendor financing arrangement which permits the Company to pay participating vendors for services and materials out of a dedicated percentage of revenue from the well. Under the terms of the agreement, the Company will 14 initially retain a net revenue interest of approximately 40% in the production attributable to the Fazzino #2. Once the vendors have recouped the face value of their respective invoices attributable to all wells drilled pursuant to this agreement, plus an agreed-upon rate of return as set forth in the agreement, the Company's net revenue interest in the Fazzino #2 will revert to approximately 80%. The Company completed construction of a gas pipeline and treatment facility in May 1999. Although the pipeline can transport up to 100,000 Mcf of gas daily, the existing treatment facility can only process up to 15,000 Mcf daily. The Company has begun constructing an additional treatment facility with a 70,000 Mcf per day capacity at an estimated cost of $3 million. The plant is expected to be completed late in the first quarter of 2000. While the Fazzino #2 is being completed, the Company is producing the Fazzino #1 at a current rate of approximately 11,000 Mcf per day. Once the Fazzino #2 is placed into production, the Company may have to shut-in or curtail production from the Fazzino #1 pending completion of the new treatment facility. During the third quarter of 1999, the Company completed its interpretation of a 3-D seismic survey conducted in southwestern Louisiana. Based on this survey, the Company has generated seven prospects on which to conduct exploratory drilling. The Company plans to spend approximately $3 million in Louisiana on seismic, leasing and exploratory drilling activities in 1999, of which $1.1 million has been incurred through September 30, 1999. The remaining $2.5 million of estimated 1999 capital expenditures, of which $1.8 million has been incurred through September 30, 1999, relate to seismic, leasing and drilling costs on various exploratory prospects, primarily in South and West Texas, and to development drilling costs on existing prospects in the Texas Gulf Coast region. The Company may increase or decrease its planned activities for 1999 depending upon drilling results, product prices, the availability of capital resources, and other factors affecting the economic viability of such activities. CAPITAL RESOURCES During the first nine months of 1999, the Company generated cash flow from operating activities of $15 million and received proceeds from sales of property and equipment of $18.5 million. During the same period, the Company repaid $15.9 million on the Credit Facility and spent $13.7 million on capital expenditures. At September 30, 1999, the Company had approximately $2 million available on the Credit Facility, as compared to $2.1 million at December 31, 1998. The Company's working capital deficit decreased from $15.8 million at December 31, 1998 to $6.5 million at September 30, 1999. The Company classified $7.8 million of its outstanding indebtedness on the Credit Facility at September 30, 1999 as a current liability based on the required levels of repayments, as compared to $15.8 million at December 31, 1998. During 1998 and continuing throughout the first quarter of 1999, the oil and gas industry operated in a depressed commodity price environment. The effects of low product prices on the Company's capital resources were pervasive and contributed significantly to declines in operating cash flow and funds available on the Credit Facility. Recent improvements in product prices have generated significant increases in operating cash flow. Accordingly, the Company plans to utilize the additional cash flow to finance higher levels of capital expenditures than originally projected for 1999. The Company believes that its operating cash flow, along with any funds which may be available on the Credit Facility, will be adequate to fund the projected capital expenditures for 1999. However, because future cash flows and the availability of borrowings under the Credit Facility are subject to a number of variables, such as prevailing prices of oil and gas, actual production from existing and newly-completed wells, the Company's success in developing and producing new reserves, and the uncertainty with respect to the amount of funds which may ultimately be required to finance the Company's exploration program, there can be no assurance that the Company's capital resources will be sufficient to sustain the Company's exploratory and development activities. 15 If the Company's operating cash flow, along with any funds which may be available on the Credit Facility, are not sufficient to fund its anticipated levels of capital expenditures, the Company may be required to seek alternative forms of capital resources, including the sale of assets and the issuance of debt or equity securities. Although the Company believes it will be able to obtain funds pursuant to one or more of these alternatives, if needed, management cannot be assured that any such capital resources will be available to the Company. If additional capital resources are needed, but the Company is unable to obtain such capital resources on a timely basis, the Company may not be able to maintain a level of liquidity sufficient to meet its obligations as they mature or maintain compliance with the required financial covenants contained in the Credit Facility. INFORMATION SYSTEMS FOR THE YEAR 2000 Historically, certain computer software systems, as well as certain hardware containing embedded chip technology, such as microcontrollers and microprocessors, were designed to utilize a two-digit date field and consequently, they may not be able to properly recognize dates in the year 2000. This could result in system failures. The Company relies on its computer-based management information systems, as well as embedded technology, to operate instruments and equipment in conducting its day-to-day business activities. Certain of these computer-based programs and embedded technology may not have been designed to function properly with respect to the application of dating systems relating to the year 2000. In response, the Company has developed a "Year 2000 Plan" and, in 1998, established an internal group to identify and assess potential areas of risk and to make any required modifications to its computer systems and equipment used in oil and gas exploration, production, gathering and gas processing activities. The Year 2000 Plan is comprised of various phases, including assessment, remediation, testing and contingency plan development. The Company believes this plan will provide reasonable assurance that its business activities and facilities will continue to operate safely and reliably, and without material interruption after 1999. The Company has completed all phases of the Year 2000 Plan as it relates to its internal systems and hardware. The Company's inventory of computer hardware and software is substantially Year 2000 compliant. The programming modifications for the oil and gas accounting and production systems were completed by the software vendor in 1997 and were installed and tested by the Company in November 1998. The Company has monitor and control equipment with embedded chip technology which are utilized in production and gas processing operations. The various systems were reviewed in conjunction with the overall Year 2000 Plan and were found to be Year 2000 compliant based on manufacturers' representations. The Company has also undertaken to monitor the compliance efforts of purchasers, vendors, contractors and other third parties ("Third Party Providers") with whom it does business and whose computer-based systems and/or embedded technology equipment interface with those of the Company to ensure that operations will not be adversely affected by the Year 2000 compliance problems of others. There can be no assurance that there will not be an adverse effect on the Company if Third Party Providers do not convert their respective systems in a timely manner and in a way that is compatible with the Company's information systems and embedded technology equipment. However, management believes that ongoing communication with and assessment of the compliance efforts and status of Third Party Providers will minimize these risks. To date, the Company has been satisfied with the ability of all significant Third Party Providers to be Year 2000 compliant on or before December 31, 1999. If it is subsequently determined that a Third Party Provider has failed to take the necessary action to become compliant, the Company is confident that an alternative Third Party Provider can be selected without any material adverse effect on the Company's operations. To date, the costs to implement the Year 2000 Plan have been nominal since the primary area for remediation involved software covered by a maintenance agreement. The Company does not expect to incur any significant costs during the remainder of 1999 to complete the Year 2000 Plan. 16 Although the Company anticipates minimal business disruptions as a result of Year 2000 issues, in the event the computer-based programs and embedded technology equipment of the Company, or that owned and operated by Third Party Providers, should fail to function properly, possible consequences include, but are not limited to, loss of communication links, inability to produce, process and sell oil and natural gas, loss of electric power, and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS The Company's business is impacted by fluctuations in commodity prices and interest rates. The following discussion is intended to identify the nature of these market risks, describe the Company's strategy for managing such risks, and to quantify the potential affect of market volatility on the Company's financial condition and results of operations. OIL AND GAS PRICES The Company's financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-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 nine months ended September 30, 1999, a $1 change in the price per barrel of oil and a $.10 change in the price per Mcf of gas would result in an aggregate change in gross revenues of approximately $1.7 million during the nine month period. From time to time, the Company has utilized hedging transactions with respect to a portion of its oil and gas production to mitigate its exposure to price fluctuations. While the use of these hedging arrangements limits the downside risk of price declines, such use may also limit any benefits which may be derived from price increases. The Company uses various financial instruments, such as swaps, collars and puts, whereby monthly settlements are based on differences between the prices specified in the instruments and the settlement prices of certain futures contracts quoted on the NYMEX or certain other indices. Generally, when the applicable settlement price is less than the price specified in the contract, the Company receives a settlement from the counterparty based on the difference. Similarly, when the applicable settlement price is higher than the specified price, the Company pays the counterparty based on the difference. The instruments utilized by the Company differ from futures contracts in that there is not a contractual obligation which requires or permits the future physical delivery of the hedged products. During 1998 and continuing throughout the first quarter of 1999, the oil and gas industry operated in a depressed commodity price environment. Oil prices during the first quarter of 1999 fell to their lowest levels in history when adjusted for inflation. Although oil and gas prices have improved significantly since April 1999, the commodity futures market remains somewhat volatile and continues to reflect the uncertainties that exist regarding near-term supply of and demand for oil and gas. In November 1997, the Company entered into swap arrangements on a significant portion of its 1998 oil production and realized a gain of $8.8 million in 1998 on oil hedges. In addition, the Company hedged a portion of its 1998 gas production at various times beginning in November 1997 and realized net gains of $1.1 million in 1998 on gas hedges. As prices declined throughout 1998, the prices at which the Company could hedge its 1999 production were generally considered by the Company to be too low to 17 effectively mitigate the downside pricing risks. However, in December 1998, the Company purchased a floor on 800,000 barrels of oil production from January 1999 through June 1999 at a price of $10.00 per barrel and hedged an aggregate of 750,000 MMBtu of gas production from January 1999 through June 1999. The gas hedge was subsequently terminated at an aggregate loss of $102,000. The Company does not have any open hedge positions as of September 30, 1999. The Company plans to enter into additional hedging arrangements when and if the market prices for future oil and gas production improve to favorable levels based on management's analysis of price expectations. INTEREST RATES All of the Company's outstanding indebtedness at September 30, 1999 is subject to market rates of interest as determined from time to time by the banks pursuant to the Credit Facility. See "CAPITAL RESOURCES". The Company may designate borrowings under the Credit Facility as either "Base Rate Loans" or "Eurodollar Loans." Base Rate Loans bear interest at a fluctuating rate that is linked to the discount rates established by the Federal Reserve Board. Eurodollar Loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these interest rates can have an adverse impact on the Company's results of operations and cash flow. Although various financial instruments are available to hedge the effects of changes in interest rates, the Company does not consider the risk to be significant and has not entered into any interest rate hedging transactions. Based on the Company's outstanding indebtedness at September 30, 1999 of $39 million, a change in interest rates of 25 basis points would affect annual interest payments by approximately $98,000. 18 PART II. OTHER INFORMATION ITEM 6 - EXHIBITS AND REPORTS ON FORM 8-K EXHIBITS
EXHIBIT NUMBER DESCRIPTION --------- --------------------------------------------------- 10.1 Third Amendment to Sixth Restated Loan Agreement dated as of August 25, 1999, among Clayton Williams Energy, Inc., Warrior Gas Co., CWEI Acquisitions, Inc., Bank One Texas, N.A., Paribas, and Union Bank of California, N.A. 27 Financial Data Schedule
REPORTS ON FORM 8-K No reports on Form 8-K were filed during the quarter ended September 30, 1999. 19 CLAYTON WILLIAMS ENERGY, INC. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized. CLAYTON WILLIAMS ENERGY, INC. Date: November 12, 1999 By: /s/ L. Paul Latham ---------------------------------- L. Paul Latham Executive Vice President and Chief Operating Officer Date: November 12, 1999 By: /s/ Mel G. Riggs ---------------------------------- Mel G. Riggs Senior Vice President and Chief Financial Officer EX-10.1 2 EXHIBIT 10.1 THIRD AMENDMENT TO SIXTH RESTATED LOAN AGREEMENT THIS THIRD AMENDMENT TO SIXTH RESTATED LOAN AGREEMENT hereinafter referred to as the "Third Amendment") executed as of the 25th day of AUGUST, 1999, by and among CLAYTON WILLIAMS ENERGY, INC., a Delaware corporation (the "CWE"), WARRIOR GAS CO., a Texas corporation ("Warrior ") (CWE and Warrior being hereinafter sometimes collectively referred to as "Borrower"), CWEI ACQUISITIONS, INC., a Delaware corporation (hereinafter referred to as "Guarantor"), BANK ONE, TEXAS, N.A., a national banking association ("Bank One"), PARIBAS, a French banking corporation ("Paribas") and UNION BANK OF CALIFORNIA, N.A. ("Union"), Bank One, Paribas and Union Bank each in their capacity as a lender hereunder together with each and every future holder of any note issued pursuant to this Agreement are hereinafter collectively referred to as "Banks", and individually as a "Bank") and Bank One, as "Agent". W I T N E S S E T H: WHEREAS, on July 16, 1998 Borrower, Guarantor, Bank One, Paribas and Agent entered into a Sixth Restated Loan Agreement (the "Sixth Restated"); and WHEREAS, as of November 20, 1998, Bank One assigned to Union and Compass Bank ("Compass") a part of its rights and obligations under the Sixth Restated and as of such date Union and Compass became parties to the Sixth Restated; and WHEREAS, as of November 20, 1998, Borrower, Guarantor, Bank One, Paribas, Union, Compass and Agent entered into a First Amendment to Sixth Restated Loan Agreement (the "First Amendment"); and WHEREAS, Union has acquired all of Compass' rights and obligations under the Sixth Restated; and WHEREAS, as of March 26, 1999, Borrower, Guarantor, Bank One, Paribas, Union and Agent entered into a Second Amendment to Sixth Restated Loan Agreement (the "Second Amendment"); and WHEREAS, the Borrower and the Banks have agreed to make certain additional changes to the Sixth Restated. NOW, THEREFORE, the parties hereto agree as follows: 1. Unless otherwise defined herein, all defined terms used herein shall have the same meaning ascribed to such terms in the Sixth Restated. 2. Section 13(b) of the Sixth Restated is hereby amended by adding the following new Subsection 13(b)(ix) thereto as follows: "(ix) guarantees by CWE of loans made by third parties to CWE employees, which loans may be extended for the sole purpose of allowing CWE employees to exercise options to purchase CWE common stock and/or to pay federal income tax liabilities relating from such exercise; provided, however, that such guarantees may not exceed $1,000,000 in the aggregate outstanding at any one time." 3. This Third Amendment shall be effective as of the date first above written, but only upon satisfaction of the conditions precedent set forth in Paragraph 4 hereto (the "Third Amendment Effective Date"). 4. The obligations of Banks under this Third Amendment shall be subject to the satisfaction of the following conditions precedent: (a) EXECUTION AND DELIVERY. The Borrower shall have executed and delivered this Third Amendment, and other required documents, all in form and substance satisfactory to the Banks; (b) GUARANTOR'S EXECUTION AND DELIVERY. The Guarantor shall have executed and delivered this Third Amendment and other required documents, all in form and substance satisfactory to the Banks; (c) CORPORATE RESOLUTIONS. Banks shall have received appropriate certified corporate resolutions of each Borrower and the Guarantor; (d) GOOD STANDING AND EXISTENCE. The Banks shall have received evidence of existence and good standing for Borrower and the Guarantor; (e) REPRESENTATIONS AND WARRANTIES. The representations and warranties of Borrower under the Sixth Restated are true and correct in all material respects as of such date, as if then made (except to the extent that such representations and warranties related solely to an earlier date); (f) NO EVENT OF DEFAULT. No Event of Default shall have occurred and be continuing nor shall any event have occurred or failed to occur which, with the passage of time or service of notice, or both, would constitute an Event of Default; (g) OTHER DOCUMENTS. Each Bank shall have received such other instruments and documents incidental and appropriate to the transaction provided for herein as such Bank or its counsel may reasonably request, and all such documents shall be in form and substance satisfactory to such Bank; and -2- (h) LEGAL MATTERS SATISFACTORY. All legal matters incident to the consummation of the transactions contemplated hereby shall be satisfactory to special counsel for Bank retained at the expense of Borrower. 5. Except to the extent its provisions are specifically amended, modified or superseded by this Third Amendment, the representations, warranties and affirmative and negative covenants of the Borrower contained in the Sixth Restated are incorporated herein by reference for all purposes as if copied herein in full. The Borrower hereby restates and reaffirms each and every term and provision of the Sixth Restated, as amended, including, without limitation, all representations, warranties and affirmative and negative covenants. Except to the extent its provisions are specifically amended, modified or superseded by this Third Amendment, the Sixth Restated, as amended, and all terms and provisions thereof shall remain in full force and effect, and the same in all respects are confirmed and approved by the Borrower and the Banks. 6. This Third Amendment may be executed in any number of counterparts and all of such counterparts taken together shall be deemed to constitute one and the same instrument. 7. The Guarantor hereby consents to the execution of this Third Amendment by the Borrower and reaffirms its guaranty of all of the obligations of the Borrower to the Bank. Borrower and Guarantor acknowledge and agree that the renewal, extension and amendment of the Loan Agreement shall not be considered a novation of account or new contract but that all existing rights, titles, powers, Liens, security interests and estates in favor of the Banks constitute valid and existing obligations and Liens and security interests as against the Collateral in favor of the Banks. Borrower and Guarantor confirm and agree that (a) neither the execution of this Third Amendment or any other Loan Document nor the consummation of the transactions described herein and therein shall in any way effect, impair or limit the covenants, liabilities, obligations and duties of the Borrower and under the Loan Documents and (b) the obligations evidenced and secured by the Loan Documents continue in full force and effect. Guarantor hereby further confirms that it unconditionally guarantees to the extent set forth in its Guaranty the due and punctual payment and performance of any and all amounts and obligations owed by the Banks under the Sixth Restated or the other Loan Documents. IN WITNESS WHEREOF, the parties have caused this Third Amendment to Sixth Restated to be duly executed as of the date first above written. BORROWER: CLAYTON WILLIAMS ENERGY, INC. a Delaware corporation By: /s/ L. PAUL LATHAM ----------------------------------- L. Paul Latham, Executive Vice President -3- WARRIOR GAS CO. a Delaware corporation By: /s/ L. PAUL LATHAM ----------------------------------- L. Paul Latham, Vice President GUARANTOR: CWEI ACQUISITIONS, INC. a Delaware corporation By: /s/ L. PAUL LATHAM ----------------------------------- L. Paul Latham, Vice President AGENT: BANK ONE, TEXAS, N.A. a national banking association By: /s/ WM. MARK CRANMER ----------------------------------- Wm. Mark Cranmer, Vice President BANKS: BANK ONE, TEXAS, N.A. a national banking association By: /s/ WM. MARK CRANMER ----------------------------------- Wm. Mark Cranmer, Vice President -4- PARIBAS a French banking corporation By: /s/ MARIAN LIVINGSTON ----------------------------------- Marian Livingston, Vice President By: /s/ BETSY JOCHER ----------------------------------- Betsy Jocher, Vice President UNION BANK OF CALIFORNIA, N.A. By: /s/ JOHN A. CLARK ----------------------------------- John A. Clark, Vice President By: /s/ GARY SHEKERJIAN ----------------------------------- Gary Shekerjian, Assistant Vice President -5- EX-27 3 EXHIBIT 27
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF THE REGISTRANT FOR THE QUARTER ENDED SEPTEMBER 30, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 9-MOS DEC-31-1999 JAN-01-1999 SEP-30-1999 5,347 0 11,269 0 896 17,855 451,021 (359,088) 109,848 24,319 31,200 0 0 899 53,430 109,848 30,105 32,842 8,286 32,053 (11,032) 0 2,162 9,659 0 9,659 0 0 0 9,659 1.08 1.05 INCLUDES $10.6 MILLION GAINS ON SALE OF PROPERTY AND EQUIPMENT.
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