================================================================================ SECURITIES AND EXCHANGE COMMISSION ------------------------------------ WASHINGTON, D.C. 20549 FORM 10-Q X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE ---------- SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended June 30, 2001 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 Number: 000-25717 [GRAPHIC OMITTED][GRAPHIC OMITTED] BETA OIL "&" GAS, INC. (Exact name of registrant as specified in its charter) Nevada 86-0876964 (State of Incorporation) (I.R.S. Employer Identification No.) 6120 S. Yale, Suite 813, Tulsa, OK 74136 (Address of principal executive offices) (Zip Code) (918) 495-1011 (Registrant's telephone number, including area code) 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 ____ As of August 1, 2001, the Registrant had 12,389,072 shares of Common Stock, $.001 par value, outstanding. ================================================================================
INDEX PAGE NO. PART 1 - FINANCIAL INFORMATION ITEM 1. Financial Statements................................................3 Condensed Consolidated Balance Sheets June 30, 2001 (unaudited) and December 31, 2000............................................3 Condensed Consolidated Statements of Operations for the three months ending June 30, 2001 and June 30, 2000 and for the six months ending June 30, 2001 and June 30, 2000 (unaudited)....... 4 Condensed Consolidated Statements of Cash Flows for the six months ending June 30, 2001 and June 30, 2000(unaudited)................5 Supplemental Disclosure of Noncash Investing and Financing Activities for the six months ending June 30, 2001 and June 30, 2000....................................................6 Notes to Condensed Consolidated Financial Statements...............7 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................................12 Disclosure Regarding Forward-Looking Statements...................12 General...........................................................12 Liquidity and Capital Resources...................................13 Plan of Operation for 2001........................................14 Comparison of Results of Operations for the three months ended June 30, 2001 and 2000 (unaudited)..............................15 Comparison of Results of Operations for the six months ended June 30, 2001 and 2000 (unaudited)..............................17 Income Taxes......................................................18 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.........18 PART II. - OTHER INFORMATION ITEM 1. Legal Proceedings..................................................19 ITEM 2. Changes in Securities..............................................19 ITEM 3. Defaults Upon Senior Securities....................................19 ITEM 4. Submission of Matters to a Vote of Security Holders ...............20 ITEM 5. Other Information..................................................20 ITEM 6. Exhibits and Reports on Form 8-K...................................20 Signatures...................................................................20 -2-PART I ITEM 1. FINANCIAL STATEMENTS BETA OIL "&" GAS, INC. CONSOLIDATED BALANCE SHEETS JUNE 30, DECEMBER 31, 2001 2000 ------------ ------------ ------------ ----------------- CURRENT ASSETS: ........................................... (Unaudited) Cash .................................................. $ 6,892,362 $ 1,536,186 Accounts receivable Oil and gas sales ................................. 2,139,958 2,766,405 Other ............................................. 247,245 95,439 Future transaction hedge asset ........................ 63,608 -- Prepaid expenses ...................................... 459,927 200,615 ------------ ------------- Total current assets .............................. 9,803,100 4,598,645 OIL AND GAS PROPERTIES, at cost (full cost method) Evaluated properties .................................. 48,307,020 43,110,463 Unevaluated properties ................................ 14,638,322 13,450,347 Less - accumulated amortization of full cost pool ..... (8,907,825) (6,354,905) ------------ ------------- Net oil "&" gas properties .................... 54,037,517 50,205,905 OTHER OPERATING PROPERTY AND EQUIPMENT, at cost Gas gathering system .................................. 1,491,184 1,454,212 Support equipment ..................................... 1,652,708 1,505,496 Other ................................................. 166,483 114,672 Less - accumulated depreciation ....................... (393,594) (158,918) ------------ ------------- Net other operating property and equipment ........ 2,916,781 2,915,462 OTHER ASSETS ............................................... 111,074 746,140 ------------ ------------- TOTAL ASSETS ............................................... $ 66,868,472 $ 58,466,152 =========== ============ CURRENT LIABILITIES: Current portion of long-term debt ..................... $ 78,871 $ 89,209 Accounts payable, trade ............................... 1,062,369 629,696 Income taxes payable .................................. 261,300 198,650 Commissions payable ................................... 238,527 -- Other accrued liabilities ............................. 660,212 147,853 ------------ ------------ Total current liabilities ......................... 2,301,279 1,065,408 LONG-TERM DEBT, less current portion ....................... 13,805,312 13,814,034 DEFERRED INCOME TAXES ...................................... 3,990,560 3,526,304 CONTINGENCIES (NOTE 7) STOCKHOLDERS' EQUITY Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,272 and 0 issued and outstanding at June 30, 2001 and December 31, 2000, respectively (Liquidation preference $6,030,171) 604 -- Common stock, $.001 par value; 50,000,000 shares authorized; 12,389,072 and 12,340,951 shares issued and outstanding at June 30, 2001 and December 31, 2000, respectively ........................................ 12,389 12,341 Additional paid-in capital ............................ 51,952,170 46,592,976 Accumulated other comprehensive income .............. 63,608 -- Accumulated deficit ................................... (5,257,450) (6,544,911) -------------- ------------ Total stockholders' equity 46,771,321 40,060,406 -------------- ------------ TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 66,868,472 $ 58,466,152 ============ ============ The accompanying notes are an integral part of these consolidated financial statements -3-BETA OIL "&" GAS, INC. CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited) For three months ended June 30, For six months ended June 30, 2001 2000 2001 2000 ----------- ----------- ----------- ----------- REVENUES: Oil and gas sales ............................. $ 3,528,536 $ 1,082,253 $ 7,864,324 $ 2,022,503 Field services ................................ 281,031 -- 641,336 -- ----------- ----------- ----------- ----------- Total revenue ............................. 3,809,567 1,082,253 8,505,660 2,022,503 ----------- ----------- ----------- ----------- COSTS AND EXPENSES: Lease operating expense ....................... 780,940 122,544 1,592,463 156,432 Field services ................................ 102,176 -- 238,217 -- General and administrative .................... 665,580 435,105 1,253,022 924,738 Depreciation and amortization expense ......... 1,401,994 611,457 2,816,197 1,172,529 ----------- ----------- ----------- ----------- Total costs and expenses .................... 2,950,690 1,169,106 5,899,899 2,253,699 ----------- ----------- ----------- ----------- INCOME (LOSS) FROM OPERATIONS ...................... 858,877 (86,853) 2,605,761 (231,196) OTHER INCOME (EXPENSE): Interest expense .............................. (229,645) (963) (502,607) (2,059) Interest income ............................... 6,977 37,274 17,886 57,287 ----------- ----------- ----------- ----------- Total other income (expense) ................ (222,668) 36,311 (484,721) 55,228 ----------- ----------- ----------- ----------- INCOME (LOSS) BEFORE TAX PROVISION ................. 636,209 (50,542) 2,121,040 (175,968) PROVISION FOR INCOME TAXES (248,122) -- (827,206) -- ----------- ----------- ----------- ----------- NET INCOME (LOSS) .................................. 388,087 (50,542) 1,293,834 (175,968) PREFERRED DIVIDENDS ................................ (6,373) -- (6,373) -- ----------- ----------- ----------- ----------- NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS .................................. $ 381,714 $ (50,542) $ 1,287,461 $ (175,968) =========== =========== =========== =========== BASIC NET INCOME (LOSS) PER COMMON SHARE ........... $ .03 $ (0.005) $ .10 $ (0.018) =========== =========== =========== =========== DILUTED NET INCOME (LOSS) PER COMMON SHARE ......... $ .03 $ (0.005) $ .10 $ (0.018) =========== =========== =========== =========== COMPREHENSIVE INCOME (LOSS): NET INCOME (LOSS) ................................. $ 388,087 $ (50,542) $ 1,293,834 $ (175,968) OTHER COMPREHENSIVE INCOME: Transition adjustment related to change in accounting for derivative instruments and hedging activities (net of income taxes) ..... -- -- (953,488) -- Reclassification of realized loss on qualifying cash flow hedges (net of income taxes) ................................ 161,373 -- 591,352 -- Unrealized gain (loss) on qualifying cash flow hedges (net of income taxes) ................. (5,524) -- 298,528 -- ----------- ----------- ----------- ----------- TOTAL COMPREHENSIVE INCOME (LOSS) .................. $ 543,936 $ (50,542) $ 1,230,226 $ (175,968) =========== =========== =========== =========== The accompanying notes are an integral part of these consolidated financial statements -4-BETA OIL "&" GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) FOR THE SIX MONTHS ENDED JUNE 30, 2001 2000 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) ...................................... $ 1,293,834 $ (175,968) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation and amortization .......................... 2,816,197 1,172,529 Deferred income tax .................................... 464,256 -- Loss on sale of asset .................................. 6,865 -- Change in operating assets and liabilities: Accounts receivable .................................... 474,641 (246,378) Prepaid expenses ....................................... (259,312) 50,030 Accounts payable, trade ................................ 432,674 75,305 Income taxes payable ................................... 62,650 -- Accrued payroll ........................................ -- (10,300) Other accrued expenses ................................. 512,356 54,166 ----------- ----------- Net cash provided by operating activities .......... 5,804,161 919,384 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas property expenditures ...................... (6,951,385) (1,244,351) Proceeds from sale of oil and gas properties ........... 726,535 -- Change in other assets ................................. 635,067 (925,104) Gas gathering and equipment expenditures ............... (287,997) -- ----------- ----------- Net cash used in investing activities .............. (5,877,780) (2,169,455) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from exercise of warrants and options ......... 156,857 2,822,686 Proceeds from premiums payable ......................... 46,957 -- Repayment of premiums payable .......................... (60,250) (15,152) Repayment of notes payable ............................. (5,770) -- Proceeds from preferred private placement .............. 5,589,390 -- Offering costs for preferred private placement ......... (529,543) -- Commission payable for private placement ............... 238,527 -- Dividends paid ......................................... (6,373) -- ----------- ----------- Net cash provided by financing activities .......... 5,429,795 2,807,534 ----------- ----------- NET INCREASE IN CASH AND CASH EQUIVALENTS .............. 5,356,176 1,557,463 CASH AND CASH EQUIVALENTS, at beginning of period ........ 1,536,186 1,448,655 ----------- ----------- CASH AND CASH EQUIVALENTS, at end of period .............. $ 6,892,362 $ 3,006,118 =========== =========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid for: Interest ........................................ $ 435,334 $ 2,059 =========== =========== Income taxes .................................... $ 300,300 $ - =========== =========== The accompanying notes are an integral part to these consolidated financial statements -5-BETA OIL "&" GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) (unaudited) SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES: FOR THE SIX MONTHS ENDED JUNE 30, 2001 2000 ---------------- ------------- Fair market value of warrants issued for: Oil and gas properties $ 143,147 $ - ================ ============= The accompanying notes are an integral part to these condensed consolidated financial statements -6-BETA OIL "&" GAS, INC. AND SUBSIDIARY NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - -------------------------------------------------------------------------------- Note 1. The accompanying condensed consolidated financial statements of Beta Oil "&" Gas, Inc. and subsidiaries ("Beta") have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions of Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly the Company's financial position as of June 30, 2001 and the results of its operations and cash flows for the three and six months ended June 30 2001 and 2000. Management believes all such adjustments are of a normal recurring nature. The results of operations for interim periods are not necessarily indicative of results to be expected for a full year. Although we believe that the disclosures in these financial statements are adequate to make the information presented not misleading, certain information normally included in financial statements and related footnotes prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission. The December 31, 2000 consolidated balance sheet was derived from audited financial statements, but does not include all disclosures required by generally accepted accounting principles. The accompanying financial statements should be read in conjunction with the audited financial statements as contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2000 that was filed April 2, 2001. Note 2. The results of operations for the three and six months ended June 30, 2001 may not necessarily be indicative of the results of operations that may be incurred for the entire fiscal year. Note 3. MERGERS, ACQUISITIONS AND SALES OF OIL AND GAS PROPERTIES On August 30, 2000, we closed the previously reported Agreement and Plan of Merger to acquire 100% interest in Red River Energy, Inc. The acquisition was consummated through a merger ("Merger") between Beta Acquisition Company, Inc., a wholly owned subsidiary of Beta, and Red River Energy, Inc. following approval of the Agreement. The effective date of the Merger was September 1, 2000. For additional information please refer to our Annual Report on Form 10-K for the fiscal year ended December 31, 2000 that was filed April 2, 2001. On June 1, 2001, the Company sold its 40% working interests in certain oil and gas properties, which represented less than 1% of the Company's proved reserves, for $710,000. The properties were located in Pecos County, Texas. On June 8, 2001, the Company purchased an additional working interest in certain oil and gas properties in which it already had an interest for approximately $726,600. The incremental interests acquired in the Waller County, Texas properties were approximately 19%. The acquisition increased the Company's proved reserves less than 1%. -7-Note 4. OIL AND GAS PROPERTIES The Company follows the full-cost method of accounting for oil and gas properties. Under this method, all productive and nonproductive costs incurred in connection with the exploration for and development of oil and gas reserves are capitalized. Such capitalized costs include lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and gas wells including salaries, benefits and other internal costs directly attributable to the activities. Costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Normal dispositions of oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized. Depreciation, depletion, and amortization of proved oil and gas properties is computed on the units-of-production method based upon estimates of proved reserves with oil and gas being converted to a common unit of measure based on the relative energy content. Unproved oil and gas properties, including any related capitalized interest costs, are not amortized, but are assessed for impairment either individually or on an aggregated basis. Note 5. STOCKHOLDERS' EQUITY Preferred Private Placement On June 29, 2001 the Company completed its Private Placement Offering of Series A 8% Convertible Preferred Stock and common stock purchase warrants, offered as units of one Preferred Share and one-half of one Warrant at $9.25 per unit. Net proceeds received from the Offering were approximately $5,059,847 net of estimated offering expenses, including brokers' commissions and other fees and expenses of $529,543. We issued 604,272 Preferred Shares and 302,136 Warrants to purchase a like number of shares of Beta's common stock at a price equal to the Offering price or $9.25 per share. Brokers were issued 59,775 non-callable warrants as part of their commission. All investors participating in the Offering were accredited. The proceeds will be used by Beta to help meet our capital requirements, including drilling costs and for other corporate purposes. The Preferred Shares may be converted by the holder at anytime at an exchange rate of one share of the Company's common stock for each one Preferred Share converted. The Preferred Shares will automatically convert into shares of Beta's common stock on a one-share for one-share basis effective the first trading day after the reported high selling price for Beta's common stock is at least 150% of the per Unit offering price of $9.25 per share or $13.875 per share for any 10 trading days. The Preferred Shares will pay quarterly cash dividends commencing in the quarter that the Preferred Shares are issued, at an annual rate of 8% per annum, simple interest. If the Preferred Shares are automatically converted into common stock or called by the Company within one year of the issuance each holder of the Preferred shares will receive a full year's dividend less any dividends previously paid during the year. Beta has the unilateral right to redeem all or any of the outstanding Preferred Shares from the date of issuance but must pay a premium if redeemed within the first five years. The holders of the Preferred Shares will be entitled to a liquidation preference equal to the stated value of the Preferred Shares plus any unpaid and accrued dividends through the date of any liquidation or dissolution of the Company. At June 30, 2001, the liquidation preference was approximately $6,030,171. Warrants are non-transferable and may be exercised at any time through June 29, 2006. -8-Proceeds from exercise of warrants and options For the six months ended June 30, 2001, gross proceeds of $156,857 have been realized from the exercise of stock warrants and options to purchase our common stock. Issuance of warrants/options During the six-month period ended June 30, 2001, 50,000 warrants, which have an exercise price of $8.13 per share, were issued for interests in certain unevaluated oil and gas properties. During the six-month period ended June 30, 2001, the Company granted 14,000 options, under our 1999 Incentive and Nonstatutory Stock Option Plan to certain employees at an average exercise price of $7.99 per share. Also, during the period the Company granted 56,000 warrants to certain employees and a director with an average exercise price of $8.31. Note 6. NET INCOME (LOSS) PER COMMON SHARE: The following represents the calculation of net income (loss) per common share: For the three months ended For the six months ended .............................. June 30, June 30, 2001 2000 2001 2000 ------------ --------------- ------------ ------------ BASIC: Net income (loss) .................. $ 388,087 $ (50,542) $ 1,293,834 $ (175,968) Less: Preferred dividends ......... (6,373) -- (6,373) -- ------------ --------------- ------------ ------------ Net income (loss) available to common shareholders ............. $ 381,714 (50,542) $ 1,287,461 $ (175,968) ============ =============== ============ ============ Weighted average number of common shares ................... 12,368,576 9,680,598 12,361,049 9,651,143 ------------ --------------- ------------ ------------ Basic earnings (loss) per share .... $ .03 $ (.005) $ .10 $ (.018) ============ =============== ============ ============ DILUTED: Net income (loss) available to common shareholders ............. $ 381,714 $ (50,542) $ 1,287,461 $ (175,968) Plus: Preferred dividends ......... 6,373 -- 6,373 -- ------------ --------------- ------------ ------------ Net income (loss) .................. $ 388,087 $ (50,542) $ 1,293,834 $ (175,968) ============ =============== ============ ============ Weighted average number of common shares ................... 12,368,576 9,680,598 12,361,049 9,651,143 Common stock equivalent shares representing shares issuable upon exercise of stock options ............................ 16,893 -- 20,382 -- Common stock equivalent shares representing shares issuable upon exercise of warrants ....... 363,086 -- 397,731 -- Common stock equivalent shares representing shares "as-if" conversion of preferred shares ... 28,035 -- 14,096 -- ------------ --------------- ------------ ------------ Weighted average number of ......... shares used in calculation of diluted income (loss) per share 12,776,590 9,680,598 12,793,258 9,651,143 ============ =============== ============ ============ Diluted earnings (loss) per share $ .03 $ (.005) $ .10 $ (.018) ============ =============== ============ ============ -9-Note 7. CONTINGENCIES On November 29, 2000 in the District Court of Tulsa County, State of Oklahoma, a Petition was filed by ONEOK Energy Marketing and Trading Company, L.P. ("ONEOK"), plaintiffs, naming the Company and two wholly-owned subsidiaries, Red River Field Services, L.L.C. and Red River Energy, L.L.C. ("Beta"), as defendants. In the lawsuit, the plaintiff alleges that Beta discontinued selling gas to the plaintiff under a fixed price agreement and sold the gas instead to other suppliers. Beta filed a counterclaim on January 24, 2001, alleging that the contract had been terminated pursuant to its terms for nonpayment by the plaintiff for gas supplied prior to termination, and seeking damages for the unpaid charges. Should the litigation be resolved adversely to Beta, the net impact to Beta is estimated to be as of June 30, 2001 approximately $270,000 plus costs and litigation expense, if recoupment from various other working interest owners in the affected oil and gas properties is successful. If Beta is unable to recoup such damages, the net adverse impact to Beta is estimated to be approximately $670,000 plus costs and litigation expense. Note 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133 (SFAS No.133), "Accounting for Derivative Instruments and Hedging Activities." The FASB has subsequently issued Statements No. 137 and Statement No. 138 which are amendments to SFAS No. 133. SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000 and cannot be applied retroactively. We adopted SFAS No. 133, as amended, beginning January 1, 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. All derivatives will be recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of transaction. Our derivative contract consists of a cash flow hedge transaction in which it hedges the variability of cash flow related to a forecasted transaction. Changes in the fair value of these derivative instruments will be recorded in other comprehensive income and will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item. The ineffective portion related to basis changes and time value of all hedges will be recognized in current period earnings. In accordance with the transition provisions of SFAS No. 133, on January 1, 2001, in connection with Beta's hedging activities, we recorded as cumulative effect adjustments a loss of $953,488 (net of $635,488 income tax) in accumulated other comprehensive loss and recorded a gain of $734,031 (net of $489,353 income tax) in the first quarter ended March 31, 2001 and a gain of $219,457 (net of $146,305 income tax) in the second quarter ended June 30, 2001. In addition, the adoption resulted in the recognition of a derivative liability on the balance sheet at January 1, 2001 and June 30, 2001 of $953,488 and $ -0-, respectively. Based on the derivative contract date, all of the transition adjustment initially recorded in accumulated other comprehensive loss was reclassified to earnings in the second quarter of 2001. -10-During the three-month period ended June 30, 2001, we entered into a commodity price hedge through the use of a "zero cost collar" contract, which has a ceiling price of $4.85 per MMBTU and a floor price of $4.00 per MMBTU. The transactions are settled based upon the average settlement price on the NYMEX for the last three trading days of the contracted month. The contract, which covers the period of July 2001 through August 2001, covers a total of 180,000 MMBTU or 60,000 MMBTU for each month in the contract period. At June 30, 2001, the contract had a fair market value of $63,608 (net of $42,406 income tax) and accordingly, we recorded a derivative asset for such amount. We realized a gain of $2,808 (net of $1,872 income tax) associated with the June settlement. The contract is costless and no net premium is received in cash or as a favorable rate. Note 9. SUBSEQUENT EVENTS Subsequent to June 30, 2001, the Company acquired an additional 15% working interest in its Brookshire Dome, Waller County, Texas leasehold acreage and producing properties for approximately $580,000. After the effect of the acquisition, the Company's total working interest in this prospect is approximately 40%, subject to a 10% "back-in" interest which reverts to the seller after the project payout, as defined in the purchase and sale agreement. -11-PART I (CONTINUED) ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. The following discussion is to inform you about our financial position, liquidity and capital resources as of June 30, 2001 and December 31, 2000 and the results of operations for the three and six-month periods ended June 30, 2001 and 2000. Disclosure Regarding Forward-Looking Statements Included in this report are 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 the Company expects or anticipates will or may occur in the future are forward-looking statements. The words "believes," "intends," "expects," "anticipates," "projects," "estimates," "predicts" and similar expressions are also intended to identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations reflected in such forward-looking statements will prove to have been correct. All forward-looking statements contained in this report are based on assumptions believed to be reasonable. These forward-looking statements include statements regarding: o Estimates of proved reserve quantities and net present values of those reserves o Reserve potential o Business strategy o Capital expenditures - amount and types o Expansion and growth of our business and operations o Expansion and development trends of the oil and gas industry o Production of oil and gas reserves o Exploration prospects o Wells to be drilled, and drilling results o Operating results and working capital We can give no assurance that such expectations and assumptions will prove to be correct. Reserve estimates of oil and gas properties are generally different from the quantities of oil and natural gas that are ultimately recovered or found. This is particularly true for estimates applied to exploratory prospects. Additionally, any statements contained in this report regarding forward-looking statements are subject to various known and unknown risks, uncertainties and contingencies, many of which are beyond our control. These and other risks and uncertainties, which are described in more detail in our Annual Report on Form 10-K filed with the Securities and Exchange Commission, could cause actual results and developments to be materially different from those expressed or implied by any of these forward-looking statements. Such things may cause actual results, performance, achievements or expectations to differ materially from the anticipated results, performance, achievements or expectations. General The energy sector experienced a moderate to strong expansion in 2000 due to higher than expected oil and natural gas prices and increased demand for oil and natural gas due to economic growth and historic below-normal temperatures in the last quarter of 2000. However, oil and natural gas prices decreased substantially by the end of the second quarter due to a national economic slowdown and at-or-below seasonal temperatures in the more populous regions of the country. Oil and natural gas prices currently remain at a level to still promote continued expansion of exploration and production. However, a further decline in these prices in the last half of 2001 and beyond could significantly limit further expansion. The constraint on equipment and manpower for drilling has somewhat eased due to the recent decline in energy prices. -12-For 2000, we experienced a record performance due to the higher oil and natural gas prices, as previously discussed, and increased production generated from our successful merger and ongoing exploration program. For the remainder of 2001, we expect to see increased production from our exploration and development efforts but do expect energy prices to be volatile and possibly further soften in the third and fourth quarters of 2001. Historically speaking, commodity prices are extremely volatile and pricing trends are extremely difficult to project. Should oil and natural gas prices continue to decline and/or our exploration efforts prove to be unsuccessful, our actual 2001 financial results will not meet our 2001 expectations. Liquidity and Capital Resources A company's liquidity is the amount of time expected to elapse until an asset can be converted to cash or conversely until a liability has to be paid. Liquidity is one indication of a company's ability to meet its obligations or commitments. Historically, our major sources of liquidity have come from internally generated cash flow from operations, funds generated from the exercise of warrants and both private and public offerings. Our working capital was a surplus of $7,501,821 at June 30, 2001 compared to a surplus of $3,533,237 at December 31, 2000. The 112% increase in working capital was primarily due to the net proceeds received from our preferred private placement, which closed on June 29, 2001. Net proceeds of approximately $5,060,000 were received in this offering and will be used for our exploration and development effort and general corporate purposes. For the first half of 2001, we incurred approximately $6.1 million in net capital expenditures associated with our exploration activity. Our cash flow from operations for the six-month period ended June 30, 2001 was significantly higher compared to the same period for 2000 due to a significant increase in production volume and the price received for natural gas, which will be discussed further in Comparison of Results of Operations. The following table represents the sources and uses of cash for the quarters indicated. For the six months ended June 30, 2001 2000 ------------ ------------ Beginning cash balance .......................................$ 1,536,186 $ 1,448,655 Sources of cash: Cash provided from operations ........................... 5,804,161 919,384 Cash provided from financing activities ................. 5,429,795 2,807,534 Cash provided from other ................................ 1,361,602 -- ------------ ------------ Total sources of cash including cash on hand.. 14,131,744 5,175,573 Uses of cash: Oil and gas expenditures ............................... (7,239,382) (1,244,351) Other assets (including advance to industry partners) .. -- (925,104) ------------ ------------ Total uses of cash ............................... (7,239,382) (2,169,455) ------------ ------------ Ending cash balance ..........................................$ 6,892,362 $ 3,006,118 ============ ============ For the six months ended June 30, 2001, funds on hand and net funds received from operations were sufficient to meet our capital requirements. For the six-month period ended June 30, 2001, we expended approximately $3.5 million for the drilling of 17 exploratory prospects of which 11 were successful. By region, the drilling results were as follows: Jackson County, Texas - $1.9 million expended on seven Frio wells (five discoveries and two dry holes) and four Yegua tests, which were unsuccessful but one well was completed successfully as a Frio producer; Waller County, Texas - $ 235,000 expended on three successful Miocene discoveries; McIntosh County, Oklahoma - $100,000 expended on one Cromwell well which was a dry hole and one Wilcox which was a discovery; Terrebonne Parish, Louisiana - $1.0 million expended on one Duvall well completed as a discovery; and $225,000 on the Shark Deep prospect, which the Company elected non-consent for completion. Additionally, $2.5 million was expended for the acquisition of additional unevaluated and undeveloped acreage in the South Texas and Louisiana areas during the six months ended June 30, 2001. -13-Subsequent to June 30, 2001, we completed four additional Frio test wells of which one well was successful and the remaining three wells were dry. Currently, we have interests in seven wells-in-progress that commenced drilling after June 30, 2001. The wells are located in the following areas: 1.) Lafourche Parish, Louisiana - Raceland prospect (7.25% working interest), 2.) Waller County, Texas - Brookshire Dome prospect (25% working interest), 3.) Jackson County, Texas - Big Twelve / Wilcox prospectand BWC/Frio prospect (both have 12.5% working interest), 4.) Wharton County, Texas - Hilje / Wilcox prospect (2.25% working interest), 5.) Muskogee County, Oklahoma - Hewitt prospect (12.5% working interest) and 6.) McIntosh County, Oklahoma - Toro prospect (15.938% working interest). To date, we have participated or are participating in the drilling of 28 wells. We also purchased an additional working interest in certain oil and gas properties, in which we already owned a working interest. The purchase price for the Brookshire Dome, Waller County, Texas interest was approximately $726,600 and was funded with the proceeds from the sale of non-operating working interests in non-strategic gas properties located in West Texas. For further discussion, please see ITEM 1. Financial Statements, Note 3. MERGERS, ACQUISITIONS AND SALES OF OIL AND GAS PROPERTIES. Subsequent to June 30, 2001, we acquired an additional 15% working interest in our Brookshire Dome, Waller County, Texas leasehold acreage and producing properties for approximately $580,000. For further discussion please see ITEM 1. Financial Statements, NOTE 9. SUBSEQUENT EVENTS. Plan of Operation for 2001 As a result of significantly higher-than-expected natural gas injection into storage during the second quarter of 2001 (this trend is continuing in the third quarter) and increasing crude oil supplies, natural gas and crude oil prices softened significantly at the end of the second quarter. Assuming no material changes in this trend, energy analysts are forecasting that natural gas and crude oil prices will be soft for the remainder of 2001. Due to this decline, our cash flow from operations (net of general and administration, interest and income taxes) will be significantly lower than our initial forecast for 2001, which had projected natural gas prices to be on average $4.50 per Mcf and crude oil prices to be on average $28.00 per barrel for the last half of 2001. However, we still anticipate that our 2001 capital expenditures will be approximately $15.0 million and expect to fund these expenditures from existing working capital, net cash flow from operation (as described above), the exercise of common stock purchase warrants and the proceeds from our recent preferred private placement. Our current projected capital expenditures for the last half of 2001 will be directed to the following: o $7.2 million for drilling of our South Texas and Louisiana prospects. Our focus in South Texas will be directed to the deeper Yegua and Wilcox tests. In Louisiana, the drilling of prospects in Lafourche Parish (which is currently drilling) and Lapeyrousse area will be the focus. Additionally, during the second quarter, we acquired proved undeveloped acreage in the Lafayette area that will be drilled in the late fourth quarter 2001 or early 2002. o $1.5 million associated with a fifteen well drilling project and 3-D seismic survey in our Brookshire Dome area located in Waller County, Texas. Additional interests in this area were acquired during and after the second quarter, with drilling to commence in the third quarter. The program will target the Miocene sands with deeper potential in the Yegua. o $1.0 million for additional acreage, seismic and smaller Mid- Continent drilling activities in Oklahoma. o With the softening pricing environment, our revised strategy for the Wind River Basin Project in Wyoming which was originally allocated $4.5 million for the exploration and development thereof, is to farm out the initial drill site, and continue to evaluate the option acreage. Current natural gas market conditions have unfavorably impacted the Rocky Mountain area with natural gas prices received in this area approximately $1.00 per Mmbtu below the current NYMEX - Henry Hub spot price. With dynamic market and pricing conditions, we must remain flexible in our commitment and application of capital to those projects that potentially offer the most favorable return. -14-o As with the Wind River Basin project, capital initially allocated to a redrill and a saltwater disposal system for the WEHLU project will be rescheduled to 2002. However, we are continuing to work with third parties on the de-watering potential in this unit, with additional testing scheduled for the last half of 2001. As with any projection, the timing and amount can vary due to the circumstances and factors beyond our control. Comparison of Results of Operations Quarter ended June 30, 2001 Compared to Quarter ended June 30, 2000 We have reported net income of $388,087 for the three-month period ended June 30, 2001 compared to a net loss of ($50,542) for the same period ended 2000. Our results of operations were significantly impacted by increased production from the Merger and our exploration activities. Also, higher natural gas prices for the period favorably impacted these results. The following table summarizes key items of comparison and their related increase (decrease) for the periods indicated. In Thousands .......................... Quarters Ended June 30 $-Increase %-Increase 2001 2000 (Decrease) (Decrease) --------- --------- --------- ---------- Net income (loss) ..................... $ 388.1 $ (50.5) $ 438.6 Oil and gas sales ..................... 3,528.5 1,082.3 2,446.2 226% Field service income .................. 281.0 -- 281.0 Operating expense ..................... 780.9 122.5 658.4 537% Field service expense ................. 102.2 -- 102.2 G"&"A expense ..................... 665.6 435.1 230.5 53% Depletion - Full cost ................. 1,268.2 608.3 659.9 108% Depreciation - Field Service and Other: 133.8 3.2 130.6 4081% Interest expense ...................... 229.6 1.0 228.6 22860% Income tax provision .................. 248.1 -- 248.1 Production: Natural Gas - Mcf ..................... 637.3 318.4 318.9 100% Crude Oil - Bbl ....................... 29.0 .5 28.5 5700% Natural Gas Equivalent - Mcfe ......... 811.1 321.6 489.5 152% $ per unit: Ave. gas price - Mcf .................. $ 4.35 $ 3.35 $ 1.00 30% Ave. oil price - Bbl .................. $ 26.11 $ 27.50 $ (1.39) (5%) Ave. operating expense - Mcfe ......... $ .96 $ .38 $ .58 153% Ave. G"&"A - Mcfe ................. $ .82 $ 1.35 $ (.53) (39%) For the three months ended June 30, 2001 oil and gas sales increased $2,446,283, or 226%, from the same period in 2000 to $3,528,536. Increased production volume of natural gas and crude oil accounted for approximately 76% of the increase in oil and gas sales for the quarter from the same period in 2000. Of the increase in sales due to volume, natural gas comprised 44% of the increase while crude oil accounted for the remaining 32%. The increased volume was due to the acquired production in the Merger and new wells put on line in the last half of 2000 and first half of 2001. Higher natural gas prices during the quarter ended 2001 accounted for additional revenues of approximately $595,600 or 24% of the overall increase in oil and gas sales from the same period in 2000. -15-Generally, we sell our natural gas to various purchasers on an indexed-based price. These indices are generally affected by the NYMEX - Henry Hub spot price. We use hedges on a limited basis to lessen the impact of price volatility. However, hedges only cover 23% of our production on an equivalent Mcf basis. For further discussion on our hedges please see Item 1. Financial Statements, Note 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. Based on our natural gas production for the three months ended June 30, 2001, a decrease in the average natural gas price realized by the Company of $1.00 per Mcf would have resulted in an approximate $637,000 reduction in net income before income taxes. Operating expenses, including production and ad valorem taxes, increased $658,396 or 537%, to $780,940 for the quarter ended June 30, 2001. The increase from the same period in 2000 was due to approximately $639,200 of additional operating expenses associated with the Merger properties with the remainder of the increase due to new wells put on production during the last half of 2000 and the first half of 2001. The average operating expense for the Merger oil and gas properties was $1.32 per equivalent Mcf for the three-month period ended June 30, 2001. This operating cost per equivalent Mcf is significantly higher than the quarterly average for the remaining properties of $.62 per equivalent Mcf due to the Merger properties being older in production life and the necessity to dispose of a significant volume of salt water produced. Additionally, due to the age of the properties, repair and maintenance costs are higher than that of the other properties. G"&"A expenses for the three months ended June 30, 2001 increased in absolute dollars by $230,475 when compared to the same period in 2000, but decreased $.53 per equivalent Mcf from the same period in 2000 to $.82 per equivalent Mcf. The increase in G"&"A expenses for the quarter ended 2001 was due to higher salaries, payroll taxes and personnel costs resulting from an increase in the number of employees since June 30, 2000. Depletion and depreciation expense increased $790,537 or 129%, to $1,401,994 for the three months ended June 30, 2001 from $611,457 for the same period in 2000. Depletion associated with evaluated oil and gas properties comprised $659,901, or 83%, of this increase. Depletion for oil and gas properties is calculated using the "Unit of Production" method, which essentially amortizes the capitalized costs associated with the evaluated properties based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. Therefore, due to the increase in production volume for the quarter ended June 30, 2001 compared to the same period ended for 2000 and the associated cost basis, depletion expense increased for the quarter. However, due to the increase of proved reserves since June 30, 2000, depletion expense on a per Mcf equivalent basis decreased by approximately $.32 per Mcf, when compared to the same period in 2000, to $1.57 per Mcf for the three months ended June 30, 2001. Depreciation expense for the three months ended June 30, 2001 was $133,828 compared to $3,192 for the same period in 2000. The increase was due to gathering assets acquired in the Merger. There were no comparable assets or associated expense at June 30, 2000. Interest expense increased for the quarter ended June 30, 2001, compared to the same period 2000 as a result of the debt acquired in the Merger. -16-Six Months ended June 30, 2001 Compared to Six Months ended June 30, 2000 We have reported net income of $1,293,834 for the six-month period ended June 30, 2001 compared to a net loss of $(175,968) for the same period ended 2000. The results of operations for this period were significantly impacted by increased production volume from the Merger and from our exploration activities and higher natural gas prices. The following table summarizes key items of comparison and their related increase (decrease) for the periods indicated. In Thousands ......................... Six Months Ended June 30 $-Increase %-Increase 2001 2000 (Decrease) (Decrease) --------- --------- --------- -------- Net income (loss) .................... $ 1,293.8 $ (176.0) $ 1,469.8 Oil and gas sales .................... 7,864.3 2,022.5 5,841.8 289% Field service income ................. 641.3 -- 641.3 -- Operating expense .................... 1,592.5 156.4 1,436.1 918% Field service expense ................ 238.2 -- 238.2 -- G"&"A expense .................... 1,253.0 924.7 328.3 36% Depletion - Full cost ................ 2,552.9 1,165.9 1,387.0 119% Depreciation - Field Service and Other 263.3 6.4 256.9 4014% Interest expense ..................... 502.6 2.1 500.5 23833% Income tax provision ................. 827.2 -- 827.2 -- Production: Natural Gas - Mcf .................... 1,248.4 650.2 598.2 92% Crude Oil - Bbl ...................... 54.3 1.7 52.6 3094% Natural Gas Equivalent - Mcfe ........ 1,574.3 660.2 914.1 138% $ per unit: Ave. gas price - Mcf ................. $ 5.12 $ 3.04 $ 2.08 68% Ave. oil price - Bbl ................. $ 27.05 $ 27.76 $ (.71) (3%) Ave. operating expense - Mcfe ........ $ 1.01 $ .24 $ .77 321% Ave. G"&"A - Mcfe ................ $ .80 $ 1.40 $ (.60) (43%) For the six months ended June 30, 2001 oil and gas sales increased $5,841,821, or 289%, from the same period ended 2000 to $7,864,324. Increased production volume of natural gas and crude oil accounted for 56% of the increase in oil and gas sales for the six months. Of the increase in sales due to higher production volume, natural gas comprised 31% of the increase while crude oil accounted for the remaining 25%. The increase in the production volume for the six months ended June 30, 2001, compared to the same period for 2000, was due to acquired production in the Merger and new wells connected in the last of half of 2000 and first half of 2001. Higher natural gas prices for the six-month period ended June 30, 2000 resulted in additional revenues of approximately $2,562,600, or 44% of the increase in oil and gas sales. Generally, we sell our natural gas to various purchasers on an indexed-based price. These indices are generally affected by the NYMEX - Henry Hub spot price. We use hedges on a limited basis to lessen the impact of price volatility. Hedges covered an average of 15% of our production on an equivalent Mcf basis for the six-month period ended June 30, 2001. Based on our natural gas production for the six months ended June 30, 2001, a change in the average natural gas price realized by the Company of $1.00 per Mcf would have resulted in an approximate $1,248,400 reduction in net income before income taxes. Operating expenses, including production and ad valorem taxes, increased $1,436,031, or 918%, to $1,592,463 for the six months ended June 30, 2001. The increased expenses were due to approximately $1,245,900 of additional operating expenses associated with the Merger properties. The remainder of the increase was due to the increase in number of wells put on production during the last half of 2000 and first half of 2001. The average operating expense for the Merger oil and gas properties was $1.28 per equivalent Mcf for the six-month -17-period ended June 30, 2001. This operating cost per equivalent Mcf is significantly higher than the six-month average for the remaining properties of $.54 per equivalent Mcf due to the Merger properties being older in production life and the necessity to dispose of a significant volume of salt water produced. Additionally, due to the age of the properties, repair and maintenance costs are higher than that of the other properties. G"&"A expenses for the six months ended June 30, 2001 increased in absolute dollars by approximately $328,284, but decreased approximately $.60 on a per equivalent Mcf basis from the same period in 2000 to $.80 per equivalent Mcf. The increase in G"&"A for the six months ended 2001 compared to the same period for 2000 was due to higher salaries and associated payroll taxes associated with additional personnel, which have been hired since June 30, 2000. Depletion and depreciation expense increased $1,643,668, or 140%, from the same period in 2000 to $2,816,197 for the six months ended June 30, 2001. Depletion associated with evaluated oil and gas properties comprised $1,386,774, or 84%, of this increase. Depletion for oil and gas properties is calculated using the "Unit of Production" method, which essentially amortizes the capitalized costs associated with the evaluated properties based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties. Therefore, due to the increase in production volume for the six-month period ended June 30, 2001 compared to the same period ended 2000 and a higher cost basis at June 30, 2001, depletion expense increased. However, due to the increase of proved reserves since June 30, 2000, depletion expense on a per Mcf equivalent basis decreased by approximately $.15 per Mcf, when compared to the same period in 2000, to $1.62 per Mcf for the three months ended June 30, 2001. Depreciation expense for the six months ended June 30, 2001 was $263,277 compared $6,383 for the same period in 2000. The increase was due to gathering assets acquired in the Merger. There were no comparable assets or associated expense at June 30, 2000. Interest expense increased for the six months ended June 30, 2001, compared to the same period 2000 as a result of the debt acquired in the Merger. Income Taxes As of June 30, 2001, we had available, to reduce future taxable income, a tax net operating loss carryforward of approximately $11,624,000, which expires in the years 2013 through 2020. Utilization of the tax net operating loss carryforward may be limited in the event a 50% or more change of ownership occurs within a three-year period. The tax net operating loss carryforward may be limited by other factors as well. As of June 30, 2001, we have a deferred tax liability of approximately $3,990,560. Item 3. Quantitative and Qualitative Disclosure About Market Risk We are exposed to market risk related to adverse changes in oil and gas prices. Our oil and gas revenues can be significantly affected by volatile oil and gas prices. This volatility can be mitigated through the use of oil and gas derivative financial hedging instruments. Currently, we have derivative financial instruments in place to mitigate the fluctuations in gas price. The hedged volume represents approximately 22% of our gas equivalent monthly production and is hedged until August 2001. Another 10% of our gas equivalent production was committed to a twelve-month fixed price contract, which was in effect until July 2001. However, in October 2000, we ceased deliveries to the purchaser due to the non-performance of payment. No further deliveries have been made under this contract and said contract is currently in litigation. The remainder of our production is not hedged and we may continue to experience wide fluctuations in oil and gas revenues as a result. For further discussion, please see ITEM 1. Financial Statements, NOTE 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. We are also exposed to market risk related to adverse changes in interest rates and credit risk. The interest volatility could be mitigated through the use of financial derivative instruments. Currently, we do not have any derivative financial instruments in place to mitigate this potential risk. -18-PART II - OTHER INFORMATION Item 1. Legal Proceedings On November 29, 2000 in the District Court of Tulsa County, State of Oklahoma, a Petition was filed by ONEOK Energy Marketing and Trading Company, L.P. ("ONEOK"), plaintiffs, naming the Company and two wholly-owned subsidiaries, Red River Field Services, L.L.C. and Red River Energy, L.L.C. ("Beta"), as defendants. In the lawsuit, the plaintiff alleges that Beta discontinued selling gas to the plaintiff under a fixed price agreement and sold the gas instead to other suppliers. Beta filed a counterclaim on January 24, 2001, alleging that the contract had been terminated pursuant to its terms for nonpayment by the plaintiff for gas supplied prior to termination, and seeking damages for the unpaid charges. Should the litigation be resolved adversely to Beta, the net impact to Beta is estimated to be as of June 30, 2001 approximately $270,000 plus costs and litigation expense, if recoupment from various other working interest owners in the affected oil and gas properties is successful. If Beta is unable to recoup such damages, the net adverse impact to Beta is estimated to be approximately $670,000 plus costs and litigation expense. Item 2. Changes in Securities On June 29, 2001 we completed our Private Placement Offering of Series A 8% Convertible Preferred Stock and common stock purchase warrants, offered as units of one Preferred Share and one half of one Warrant at $9.25 per unit. The terms of the securities are described in Note 5 to the Financial Statements included as Item 1, Part I of this report. Net proceeds received from the Offering were approximately $5,059,847 net of estimated offering expenses, including brokers' commissions and other fees and expenses of $529,543. We issued 604,272 Preferred Shares and 302,136 Warrants to purchase a like number of shares of Beta's common stock at a price equal to the Offering price or $9.25 per share. All investors participating in the Offering were accredited. The offering was exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of the exemption provided by Section 4(2) of that act and Rule 506 of Regulation D promulgated by the Securities and Exchange Commission. The proceeds will be used by Beta to help meet our capital requirements, including drilling costs and for other corporate purposes. On March 6, 2001, 50,000 non-callable common stock purchase warrants were issued to Leonard Ross in consideration for the purchase of an unevaluated oil and gas prospect. The non-callable common stock purchase warrants will expire on March 6, 2008 and have an exercise price of $8.134. In addition, 56,000 non-callable common stock purchase warrants have been issued during the six-month period ended January 1, 2001 to certain employees and a director with an average exercise price of $8.31 and will expire in 2006. Also, during the period the Company granted 14,000 options under our 1999 Incentive and Nonstatutory Stock Option Plan to certain employees at an average exercise price of $7.99 per share. During the six-month period ending June 30, 2001, the Company realized $156,857 in gross proceeds from the exercise of stock warrants to purchase our common stock. These common stock purchase warrants ranged in exercise price from $2.00 to $7.00 and were originally issued in 1997 and 1998. No underwriter was used in the issuance of the stock warrants. In connection with the issuance of these securities we relied upon Section 4(2) of the Securities Act in claiming exemption for the registration requirements of the Securities Act. All of the persons to whom the securities were issued had full information concerning the business and affairs of the Company and acquired the shares for investment purposes. Certificates representing the securities issued bear a restrictive legend and stop transfer instructions have been entered prohibiting transfer of the securities except in compliance with applicable securities law. Item 3. Defaults Upon Senior Securities Not applicable. Item 4. Submission of Matters to a Vote of Security Holders Our annual meeting of shareholders was held at Warren Place Two, 6120 South Yale Avenue, Tulsa, Oklahoma on Saturday, June 2, 2001, at 10:00 A.M. Central Daylight Time. The matters submitted to a vote of our shareholders as well as the results of the votes cast are as follows: Matters voted upon by holders of common stock: Proposal No.1: Election of directors. A summary of the votes cast is as follows: % of out- % of out % of out- Number standing standing Number standing For shares shares Withheld shares ---------- ------ ---- -------- ------- Steve Antry ............ 11,004,764 99.658 0.00% 37,787 0.342% R. Thomas Fetters ...... 11,004,764 99.658 0.00% 37,787 0.342% Joe C. Richardson, Jr .. 11,004,764 99.658 0.00% 37,787 0.342% John P. Tatum .......... 11,004,764 99.658 0.00% 37,787 0.342% Robert C. Stone, Jr .... 11,004,764 99.658 0.00% 37,787 0.342% As a result of the voting, Steve Antry, R. Thomas Fetters, Joe C. Richardson, Jr., John P. Tatum and Robert C. Stone, Jr. were elected as the Company's directors to serve in that capacity until the Annual Shareholders Meeting in 2002. -19-Proposal No. 2: Ratification of Appointment of Independent Auditors. A summary of the votes cast is as follows: % of out- % of out- % of out- Number standing Number standing Number standing For shares Against shares Withheld shares - ----------- ----------- ------- -------- ----------- --------- 1,007,724 99.685% 400 0.004% 34,427 0.312% As a result of the vote, Hein + Associates LLP was appointed auditors for the Company for the year 2001. Item 5. Other Information Not applicable. Item 6. Exhibits and Reports on Form 8-K (a) Exhibit 3.1 Certificate of Designation of 8% Cumulative Convertible Preferred Stock filed as an exhibit to the Form 8-K dated June 29, 2001 and incorporated herein by reference, ( http://www.sec.gov/Archives /edgar/data/1059324/000105932400000042/0001059324-01-500009.txt). Exhibit 4.1 Warrant Agreement and Exhibit A to Warrant Agreement comprised of Warrant Certificates A and B filed as an exhibit to the Form 8-K dated June 29, 2001 and incorporated herein by reference, ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/ 0001059324-01-500009.txt). Exhibit 4.2 Preferred Stock Certificate Form (b) The following reports were filed on Form 8-K during the quarter ended June 30, 2001: (1) June 29, 2001 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 who is duly authorized. BETA OIL "&" GAS, INC. Date: August 7, 2001 By /s/ Joseph L. Burnett ------------------------ Joseph L. Burnett Chief Financial Officer and Principal Accounting Officer -20-