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SECURITIES AND EXCHANGE COMMISSION
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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 September 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 November 1, 2001, the Registrant had 12,369,072 shares of Common Stock, $.001 par value, outstanding. ================================================================================
INDEX
PAGE NO.
PART 1 - FINANCIAL INFORMATION
ITEM 1. Financial Statements.........................................................3
Condensed Consolidated Balance Sheets as of September 30, 2001
(unaudited) and December 31, 2000.......................................3
Condensed Consolidated Statements of Operations for the three months
ending September 30, 2001 and September 30, 2000 and for the nine
months ending September 30, 2001 and September 30, 2000 (unaudited).... 4
Condensed Consolidated Statements of Cash Flows for the nine months
ending September 30, 2001 and September 30, 2000 (unaudited)............5
Supplemental Disclosure of Noncash Investing and Financing
Activities for the nine months ending September 30, 2001 and
September 30, 2000......................................................6
Notes to Condensed Consolidated Financial Statements.......................7
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations..........................................................13
Disclosure Regarding Forward-Looking Statements...........................13
General...................................................................13
Liquidity and Capital Resources...........................................14
Plan of Operation for 2001................................................16
Comparison of Results of Operations for the three months ended
September 30, 2001 and 2000 ...........................................18
Comparison of Results of Operations for the nine months ended
September 30, 2001 and 2000 ...........................................20
Income Taxes..............................................................21
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.................21
PART II. - OTHER INFORMATION
ITEM 1. Legal Proceedings........................................................23
ITEM 2. Changes in Securities....................................................23
ITEM 3. Defaults Upon Senior Securities..........................................23
ITEM 4. Submission of Matters to a Vote of Security Holders .....................23
ITEM 5. Other Information........................................................23
ITEM 6. Exhibits and Reports on Form 8-K.........................................23
Signatures............................................................................23
PART I ITEM 1. FINANCIAL STATEMENTS BETA OIL & GAS, INC. CONSOLIDATED BALANCE SHEETS
SEPT. 30, 2001 DEC. 31, 2000
------------ ------------
CURRENT ASSETS: ....................................................... (Unaudited)
Cash .............................................................. $ 3,091,221 $ 1,536,186
Accounts receivable - Oil and gas ................................. 2,534,774 2,766,405
Accounts receivable - Other ....................................... 43,993 95,439
Future transaction hedge asset .................................... 172,499 --
Income tax receivable ............................................. 115,425 --
Prepaid expenses .................................................. 267,976 200,615
------------ ------------
Total current assets .......................................... 6,225,888 4,598,645
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties .............................................. 51,846,859 44,398,497
Unevaluated properties ............................................ 16,034,300 13,450,347
Less - accumulated amortization and impairment of full cost pool .. (16,677,518) (6,395,326)
------------ ------------
Net oil & gas properties .................................. 51,203,641 51,453,518
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system .............................................. 1,497,867 1,454,212
Support equipment ................................................. 221,413 217,462
Other ............................................................. 177,507 114,672
Less - accumulated depreciation ................................... (356,204) (118,497)
------------ ------------
Net other operating property and equipment .................... 1,540,583 1,667,849
OTHER ASSETS ........................................................... 1,348,522 746,140
------------ ------------
TOTAL ASSETS ........................................................... $ 60,318,634 $ 58,466,152
============ ============
CURRENT LIABILITIES:
Current portion of long-term debt ................................ $ 148,703 $ 89,209
Accounts payable, trade .......................................... 1,204,126 629,696
Owner advances ................................................... 932,558 --
Income taxes payable ............................................. -- 198,650
Dividends payable ................................................ 112,707 --
Other accrued liabilities ........................................ 238,809 147,853
------------ ------------
Total current liabilities ..................................... 2,636,903 1,065,408
LONG-TERM DEBT, less current portion ................................... 13,702,056 13,814,034
DEFERRED INCOME TAXES .................................................. 2,133,079 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 September 30, 2001
and December 31, 2000 (Liquidation preference $6,030,171) ....... 604 --
Common stock, $.001 par value; 50,000,000 shares authorized;
12,392,571 and 12,340,951 shares issued and 12,366,071 and
12,340,951 outstanding at September 30, 2001 and December 31,
2000, respectively ............................................. 12,393 12,341
Additional paid-in capital ....................................... 51,818,493 46,592,976
Accumulated other comprehensive income ......................... 172,499 --
Treasury stock, at cost; 26,500 shares reacquired at September 30,
2001 ........................................................... (130,155) --
Accumulated deficit .............................................. (10,027,238) (6,544,911)
------------ ------------
Total stockholders' equity 41,846,596 40,060,406
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 60,318,634 $ 58,466,152
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The accompanying notes are an integral part of these consolidated financial statements
BETA OIL & GAS, INC. CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)
For three months ended Sept.30, For nine months ended Sept.30,
2001 2000 2001 2000
------------ ------------ ------------ ------------
REVENUES:
Oil and gas sales ............................ $ 2,398,684 $ 1,967,777 $ 10,263,008 $ 3,990,280
Field services 132,645 55,000 773,981 55,000
------------ ------------ ------------ ------------
Total revenue ............................ 2,531,329 2,022,777 11,036,989 4,045,280
------------ ------------ ------------ ------------
COSTS AND EXPENSES:
Lease operating expense ...................... 847,678 303,835 2,440,141 460,267
Field services 59,930 29,488 298,147 29,488
General and administrative ................... 611,229 651,576 1,864,251 1,576,314
Depreciation and amortization expense ........ 962,193 138,742 3,778,390 1,311,271
Full cost ceiling impairment ................. 6,770,110 -- 6,770,110 --
------------ ------------ ------------ ------------
Total costs and expenses ................... 9,251,140 1,123,641 15,151,039 3,377,340
------------ ------------ ------------ ------------
INCOME (LOSS) FROM OPERATIONS ..................... (6,719,811) 899,136 (4,114,050) 667,940
OTHER INCOME (EXPENSE):
Interest expense ............................. (203,497) (92,478) (706,104) (94,537)
Interest income .............................. 36,055 33,783 53,941 91,070
------------ ------------ ------------ ------------
Total other income (expense) ............... (167,442) (58,695) (652,163) (3,467)
------------ ------------ ------------ ------------
INCOME (LOSS) BEFORE TAX PROVISION ............... (6,887,253) 840,441 (4,766,213) 664,473
INCOME TAX BENEFIT ................................ 2,230,206 -- 1,403,000 --
------------ ------------ ------------ ------------
NET INCOME (LOSS) ................................. (4,657,047) 840,441 (3,363,213) 664,473
PREFERRED DIVIDENDS .............................. (112,741) -- (119,114) --
------------ ------------ ------------ ------------
NET INCOME (LOSS) AVAILABLE TO COMMON
SHAREHOLDERS ................................. $ (4,769,788) $ 840,441 $ (3,482,327) $ 664,473
============ ============ ============ ============
BASIC NET INCOME (LOSS) PER COMMON SHARE ......... $ (.39) $ 0.078 $ (.28) $ 0.066
============ ============ ============ ============
DILUTED NET INCOME (LOSS) PER COMMON SHARE ....... $ (.39) $ 0.073 $ (.28) $ 0.062
============ ============ ============ ============
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS) ................................ $ (4,657,047) $ 840,441 $ (3,363,213) $ 664,473
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 (gain) loss on
qualifying cash flow hedges (net of
income taxes) ............................... (91,800) -- 499,552 --
Unrealized gain (loss) on qualifying cash flow
hedges (net of income taxes) ................ 200,690 -- 626,435 --
------------ ------------ ------------ ------------
TOTAL COMPREHENSIVE INCOME (LOSS) ................. $ (4,548,157) $ 840,441 $ (3,190,714) $ 664,473
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The accompanying notes are an integral part of these consolidated financial statements
BETA OIL & GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
FOR THE NINE MONTHS ENDED SEPT 30, 2001 2000
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) ................................................ $ (3,363,213) $ 664,473
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation and amortization .................................... 3,778,390 1,311,271
Full cost ceiling impairment ..................................... 6,770,110 --
Deferred income tax .............................................. (1,393,225) --
Loss on sale of asset ............................................ 6,865 --
Warrants issued for services ..................................... -- 128,338
Change in operating assets and liabilities:
Accounts receivable .............................................. 283,077 (548,276)
Income tax receivable ............................................ (115,425) --
Prepaid expenses ................................................. (67,361) 6,363
Accounts payable, trade .......................................... 574,431 63,936
Owner advances ................................................... 932,558 --
Income taxes payable ............................................. (198,650) --
Other accrued expenses ........................................... 90,956 (12,810)
------------ ------------
Net cash provided by operating activities .................... 7,298,513 1,613,295
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CASH FLOWS FROM INVESTING ACTIVITIES:
Cash received in acquisition of RRE .............................. -- 895,097
Oil and gas property expenditures ................................ (10,742,315) (2,834,679)
Proceeds from sale of oil and gas properties ..................... 726,535 --
Change in other assets ........................................... (602,382) (2,213,435)
Gas gathering and equipment expenditures ......................... (162,443) (14,775)
------------ ------------
Net cash used in investing activities ....................... (10,780,605) (4,167,792)
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CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of warrants and options .................. 168,857 3,203,390
Proceeds from premiums payable .................................. 152,680 --
Repayment of premiums payable ................................... (96,420) (22,294)
Proceeds from notes payable ..................................... 900,000 256,504
Repayment of notes payable ...................................... (1,008,744) (536,296)
Proceeds from preferred stock private placement ................. 5,589,390 --
Offering costs for preferred stock private placement ............ (532,074) --
Dividends paid .................................................. (6,407) --
Acquisition of treasury stock ................................... (130,155) --
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Net cash provided by financing activities ..................... 5,037,127 2,901,304
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NET INCREASE IN CASH AND CASH EQUIVALENTS ........................ 1,555,035 346,807
CASH AND CASH EQUIVALENTS, at beginning of period .................. 1,536,186 1,448,655
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CASH AND CASH EQUIVALENTS, at end of period ........................ $ 3,091,221 $ 1,795,462
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SUPPLEMENTAL DISCLOSURE OF CASH FLOW ...............................
INFORMATION
Cash paid for:
Interest .................................................. $ 706,104 $ 92,478
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Income taxes .............................................. $ 304,300 $ 8,000
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The accompanying notes are an integral part to these consolidated financial statements
BETA OIL & GAS, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) (unaudited) SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
FOR THE NINE MONTHS ENDED SEPT 30,
2001 2000
------------ -----------
Net assets acquired, net of cash, through acquisition of RRE ..... $ -- $13,459,903
Common stock & warrants issued in settlement of debt ......... -- 312,280
The accompanying notes are an integral part to these consolidated financial statements
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 September 30, 2001 and the results of its operations and cash flows for the three and nine months ended September 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 nine months ended September 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 additional working interests in certain oil and gas properties located in the Brookshire Dome area, Waller County Texas, in which it had existing working interests, for approximately $726,600. However, certain existing working interest owners in these properties exercised their preferential right to purchase their pro-rata share of the interests originally purchased by us. Upon the exercise of this right in August 2001, we were reimbursed by the other owners approximately $454,100 of our original acquisition cost. Our net acquisition cost, after reimbursement, was approximately $272,500 for an approximate 11.71% working interest. The proved reserves associated with this acquisition were less than 1% of our total proved reserves. In August 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. 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. Capitalized costs of evaluated properties, less accumulated amortization and related deferred income taxes, shall not exceed an amount ("the cost ceiling") equal to the sum of the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current economic and operating conditions discounted at 10%, plus the cost of properties not being amortized less any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this cost ceiling, the excess is charged to earnings. Unproved or unevaluated properties, including any related capitalized interest costs, are not amortized, but are assessed for impairment either individually or on an aggregated basis. At September 30, 2001, the Company recorded a non-cash impairment charge on its U.S. domestic evaluated properties of $6,770,110 due to a significant decline in the estimated present value of future net cash flows from these properties as a result of lower natural gas and crude oil prices at September 30, 2001. The prices used for the estimation were $2.20 per Mmbtu for natural gas and $23.50 per barrel for crude oil. The prices used for this estimation at June 30, 2001 and December 31, 2000 were $3.09 per Mmbtu for natural gas and $26.25 per barrel for crude oil and $9.23 per Mmbtu for natural gas and $26.80 per barrel for crude oil, respectively. Due to the volatility of commodity prices, should natural gas and crude oil prices decline in the future, even if only for a brief period of time, it is possible that additional impairments of oil and gas properties could occur. The price measurement date is on the last day of the quarter or year-end and is required by SEC rules. 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 $5,057,316 net of estimated offering expenses, including brokers' commissions and other fees and expenses of $532,074. 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% of the stated value. 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 September 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. Treasury Stock On September 19, 2001 the Company's Board of Directors authorized a stock repurchase program for up to an aggregate of $1,000,000 of the Company's common stock over the next four months. The repurchase program was effective on September 19, 2001. At September 30, 2001, the Company had reacquired 26,500 shares for a total cost of $130,155 or $4.91 per share. The authorization to repurchase shares was facilitated in part by an Order issued by the Securities and Exchange Commission on September 14, 2001. The Order temporarily increased the flexibility with respect to certain SEC rules pertaining to issuer stock repurchases. The timing and amount of shares actually to be purchased in the future is being determined at Beta management's discretion, based on market conditions and other factors. Proceeds from exercise of warrants and options For the nine months ended September 30, 2001, gross proceeds of $168,857 have been realized from the exercise of stock warrants and options to purchase our common stock. Issuance of warrants/options During the three-month period ended September 30, 2001, 50,000 warrants that were previously issued for interests in certain unevaluated oil and gas properties were cancelled on August 31, 2001 due to non-performance. During the nine-month period ended September 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 nine months ended
September 30, September 30,
2001 2000 2001 2000
------------- ------------- ------------- ------------
BASIC:
Net income (loss) ...................... $ (4,657,047) $ 840,441 $ (3,363,213) $ 664,473
Less: Preferred dividends ............. (112,741) -- (119,114) --
------------- ------------- ------------- ------------
Net income (loss) available to
common shareholders ................. $ (4,769,788) $ 840,441 $ (3,482,327) $ 664,473
============= ============= ============= ============
Weighted average number of
common shares ....................... 12,388,456 10,801,585 12,370,286 10,035,804
------------- ------------- ------------- ------------
Basic earnings (loss) per share ........ $ (.39) $ .078 $ (.28) $ .066
============= ============= ============= ============
DILUTED:
Net income (loss) available to
common shareholders ................. $ (4,769,788) $ 840,441 $ (3,482,327) $ 664,473
Plus: Preferred dividends ............. 112,741 -- 119,114 --
------------- ------------- ------------- ------------
Net income (loss) ...................... $ (4,657,047) $ 840,441 $ (3,363,213) $ 664,473
============= ============= ============= ============
Weighted average number of
common shares ....................... 12,388,456 10,801,585 12,370,286 10,035,804
Common stock equivalent shares
representing shares issuable
upon exercise of stock options ...... Anti-dilutive 37,646 Anti-dilutive 28,744
Common stock equivalent shares .........
representing shares issuable
upon exercise of warrants ........... Anti-dilutive 652,382 Anti-dilutive 691,339
Common stock equivalent shares
representing shares "as-if"
conversion of preferred shares ...... Anti-dilutive -- Anti-dilutive --
------------- ------------- ------------- ------------
Weighted average number of
shares used in calculation of
diluted income (loss) per share 12,388,456 11,491,613 12,370,286 10,755,887
============= ============= ============= ============
Diluted earnings (loss) per share ...... $ (.39) $ .073 $ (.28) $ .062
============= ============= ============= ============
| | Since the Company had a net loss for the three and nine months ended September 30, 2001, all common stock equivalents had an anti-dilutive impact on (reduced) the basic loss per share calculation. Therefore, all common stock equivalents were not considered in the weighted average per share calculation for these periods. |
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 September 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 of $953,488. 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. |
| | Natural Gas - At September 30, 2001, the Company had entered into commodity price hedging contracts as set forth below with respect to our 2001 and 2002 natural gas production. The hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days of a particular contract month. |
NYMEX Contract Price per MMBtu ------------------------------ Volume in Collars Period MMBtus Floor Ceiling June 01- Aug 01 180,000 $4.00 $4.85 Sept 01 - Feb 02 362,000 $3.50 $3.85
| | At September 30, 2001, the outstanding contracts had a fair market value of $134,217 (net of $89,478 income tax) and accordingly recorded a derivative asset for such amount. We realized a gain for the contracts settled in the quarter ended September 30, 2001 of $91,800 (net of $61,200 income tax). These contracts are costless and no net premium is received in cash or as a favorable rate. |
| | Crude Oil - At September 30, 2001, the Company had entered into commodity price hedging contracts as set forth below with respect to our 2001 and 2002 crude oil production. The hedging transactions are settled based upon the average of the reported daily settlement prices per barrel for West Texas Intermediate Light Sweet Crude Oil on the NYMEX for each trading day of a particular contract month. |
NYMEX Contract Price per Barrel ------------------------------ Volume in Collars Period Barrels Floor Ceiling Oct 01- Mar 02 30,000 $25.00 $27.90
| | At September 30, 2001, the outstanding contracts had a fair market value of $38,282 (net of $25,521 income tax) and accordingly recorded a derivative asset for such amount. No gain has been realized since the contract settlement dates are for future periods after September 30, 2001. These contracts are costless and no net premium is received in cash or as a favorable rate. |
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 September 30, 2001 and December 31, 2000 and the results of operations for the three and nine-month periods ended September 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 and new production. 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 present economic environment, both international and domestic, has deteriorated substantially in 2001 and has impacted many industry sectors including the energy sector. With significant decreases in demand and build up in supply, both natural gas and crude oil prices have significantly decreased during the nine-month period ended September 30, 2001. The prospect for strengthening in these commodity prices remains uncertain. For the remainder of 2001, we expect our level of production volume to increase from our present exploration and development activities. However, the impact of the increased volume will be lessened due to the soft natural gas and crude oil prices. We are an exploration company and see opportunity for growth through our current exploration and development projects on hand and will continue our present drilling activity in spite of the current economic environment but will have to remain flexible in our timing and ranking in our projects. 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 $3,588,985 at September 30, 2001 compared to a surplus of $3,533,237 at December 31, 2000. For the first three quarters of 2001, we incurred approximately $10.7 million in capital expenditures associated with our exploration and development activity, which included drilling, production acquisition and leasehold acquisition. Our cash flow from operations for the nine-month period ended September 30, 2001 was significantly higher compared to the same period for 2000 due to a significant increase in production volume and the price received for natural gas, which will be discussed further in Comparison of Results of Operations.
For the fourth quarter of 2001, we do expect our working capital and liquidity to decrease significantly due to the drilling of two of our more costly and higher impact prospects and the continuation of our drilling program in the Brookshire Dome area, as discussed below in our Plan of Operation for 2001. The following table represents the sources and uses of cash for the quarters indicated.
For the nine months ended
September 30,
2001 2000
----------- -----------
Beginning cash balance ........................................$ 1,536,186 $ 1,448,655
Sources of cash:
Cash provided from operations ............................ 7,298,513 1,613,295
Cash provided from financing activities .................. 5,037,127 2,901,304
Cash provided from investing activities .................. 726,535 895,097
----------- -----------
Total sources of cash including cash on hand 14,598,361 6,858,351
Uses of cash:
Oil and gas expenditures ................................ (10,742,315) (2,834,679)
Other assets (including advance to industry partners) ... (602,382) (2,213,435)
Gas gathering and equipment expenditures ................ (162,443) (14,775)
----------- -----------
Total uses of cash ............................... (11,507,140) (5,062,889)
----------- -----------
Ending cash balance ...........................................$ 3,091,221 $ 1,795,462
=========== ===========
For the nine-month period ended September 30, 2001, approximately $10.7 million was expended on our exploration and development program, including the acquisition of additional working interests in production and leasehold acreage, both proved and unproved. To date for 2001, we have participated in the drilling of 43 gross wells (9.34 net wells) of which 25 gross wells (5.235 net wells) were successfully completed, 12 gross wells (2.69 net wells) were dry holes, two gross wells (.46 net wells) are currently under evaluation and four gross wells (.948 net wells) are drilling or completing. By region, the drilling results to date are as follows:
1.) Jackson and Wharton Counties, Texas - To date for 2001, 20 gross wells (2.698 net wells) have drilled or are drilling, including 13 Frio wells (seven discoveries and six dry holes with our working interests ranging from 12.5% to 25%), five Yegua test wells (one discovery, two successfully completed as Frio wells with our working interests ranging from 12.5% to 25%) and two Wilcox wells (one currently being completed as Yegua, in which we have a 12.5% working interest and one currently is drilling, in which we have a 2.25% working interest). For the nine months ended September 30, 2001, approximately $3.7 million was expended on drilling and leasehold acquisition. The combined successfully completed wells are currently producing approximately 2,000 gross Mcf (822 net Mcf) of natural gas per day.
2.) Waller County, Texas (Brookshire Dome Area)- We have drilled 13 gross Miocene wells (3.89 net wells); eight discoveries, two currently under evaluation, one dry hole and two drilling. For the nine months ended September 30, 2001, total costs expended for the drilling and completion of these wells was approximately $343,700. Additionally, incremental working interests in producing properties and
| | leasehold acreage, in which we have existing working interests, were acquired in two separate transactions. In June 2001, additional working interests in leasehold acreage and the Whitt Bains wells were acquired at an initial cost of $726,600. However, certain existing working interest owners in these properties exercised their preferential right to purchase their pro-rata share of the interests originally purchased by us. Upon the exercise of this right in August 2001, we were reimbursed by the other owners approximately $454,100 of our original acquisition cost. Our net acquisition cost, after reimbursement, was approximately $272,500 for an approximate 11.71% working interest. In the second transaction, which occurred in August 2001, we acquired a 15% working interest in two producing wells and certain leasehold acreage in the same area for a total cost of approximately $579,700. These purchases were funded with 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. The current production from our Brookshire Dome area is 720 gross barrels (153 net barrels) of oil per day. |
3.) Red River and Lamar Counties, Texas (Detroit prospect) - For the nine-month period ended September 30, 2001, approximately $372,000 was expended on additional leasehold acreage. We have a 75% working interest in approximately 14,000 acres and expect to drill the initial well in this prospect in early 2002. As planned, we will reduce our working interest position to recover some or all of our acreage cost and to partially fund our share of drilling cost.
4.) Louisiana - To date for 2001, we have participated in the drilling of three wells in the south Louisiana area. One well, the T.Cenac #1 located in Terrebonne Parish, was completed in the Duval sand and went on line in September 2001 and is currently producing approximately 9,270 gross Mcf (1,082 net Mcf) of natural gas per day and 225 gross barrels (25 net barrels) of condensate per day. Total cost expended for the nine months ended September 30, 2001 for drilling and acreage is approximately $1.3 million. We have an approximate 16.2% working interest in this area. The second well, the Dore #1 located in Vermillion Parish, was a 12,500 ft. exploratory test in the Live Oak field and reached total depth subsequent to September 30, 2001. The test, in which we had a 50% interest, proved unsuccessful and the well was plugged and abandoned in October 2001. Our total cost including acreage, promote and dry hole cost will be approximately $607,000. Our third well, the W. Ponson #1 located in La Fourche Parish, commenced drilling in July 2001. The 16,800 ft. exploratory test for the Rob sands reached total depth and logged in early October 2001. After a lengthy evaluation period, elections were made by the working interest owners to abandon the well due to sand quality. At September 30, 2001, our total cost, including acreage, was approximately $250,000.
| | We have also acquired proved and unproved acreage in the West Broussard area. Approximately 1,100 leasehold acres have been acquired in 2001 at a cost of approximately $1.7 million. A portion of the acreage offsets existing production and has evaluated proved undeveloped reserves. We expect to receive approval on our unitization proposal in late fourth quarter 2001 and commence drilling in early 2002. Before drilling, we will reduce our current working interest in this prospect to recover a portion or all of our cost and fund our share of the drilling costs. We have a similar smaller prospect in the Lake Beouff area in which approximately 663 leasehold acres have been leased at a total cost of approximately $200,000. |
| | Our approach will be similar to West Broussard, in that we will file for unitization in the fourth quarter of 2001 and expect to commence drilling in mid-2002. Currently, we have a 100% working interest in this acreage but will reduce our ownership percentage to recover our acreage cost and assist in funding our share of the drilling cost. |
5.) McIntosh and Muskogee Counties, Oklahoma - We have participated in the drilling of seven wells (six discoveries and one dry hole) targeting the Atoka, Booch or Gilcrease sands. With working interests in these wells ranging from 12.5% to 18.75%, a total of approximately $400,000 has been expended in the nine months ended September 30, 2001. The current production associated from these wells is approximately 1,066 gross Mcf (152 net Mcf) of natural gas per day. One well is shut-in awaiting pipeline connection.
Plan of Operation for 2001
As a result of significantly higher-than-expected natural gas injection into storage during the second and third quarter of 2001 and increasing crude oil supplies, natural gas and crude oil prices have decreased significantly. Some energy analysts are seeing no material change in this trend and are forecasting that natural gas and crude oil prices will be soft for the remainder of 2001, except for potential of strengthening due to seasonal demand, and into 2002. In spite of the trend, our earlier forecasts for a 2001 capital expenditure program of approximately $15.0 million appeared achievable at the end of the second quarter ended June 30, 2001. However, due to timing delays in outside operated projects that were scheduled for the fourth quarter, which can be partially attributed to the decline in natural gas and crude oil prices, and timing delays in certain of our own prospects, we now expect our total capital expenditures to be in the range of $13 million to $14 million for 2001. We currently project our fourth quarter 2001 expenditures to approximate $3 million to $4 million. With the decline in natural gas and crude oil prices, our cash flow from operations (net of general and administration, interest and income taxes) from the second and third quarters of 2001 was 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 expect to fund the fourth quarter 2001 expenditures from existing working capital, including the proceeds from the recent preferred private placement, cash flow from operations, occasional exercise of common stock purchase warrants and, as previously discussed, funds received in the reduction of interest in certain projects.
Our current projected capital expenditures for the fourth quarter of 2001 will be directed to the following:
o $1.6million for the drilling of the Greens Lake - Sara White prospect located in Galveston County, Texas. The 15,400 ft. exploratory well is to commence drilling in late November 2001. Currently, we have a 42% working interest but may reduce this interest to 29.5% before commencement of drilling. We have prepaid our share of dry-hole cost based on 42%.
o $1.1 million for the drilling of the Matterhorn prospect located in Jackson County, Texas, which is a 18,000 ft. exploratory well. We currently have a 22.5% working interest in this well, which is to commence drilling in late October 2001, but may reduce this interest to 12.5% before the well reaches total depth. Our share of the dry-hole cost, based on our current 22.5% working interest, is approximately $890,000.
o $1.1 million for additional drilling in the Brookshire Dome area located in Waller County, Texas. This includes approximately $400,000 related to a seismic survey, which will be completed in the fourth quarter 2001.
o $.3 million related to various acreage acquisition and seismic studies.
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.
o As with the Wind River Basin project, capital initially allocated to a re-drill 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 in progress on one of the test wells drilled earlier this year.
As with any projection, the timing and amount can vary due to the circumstances and factors beyond our control.
Our planned capital expenditures could exceed our latest projections and could exceed our cash from all sources. Due to the volatility of natural gas and crude oil prices, while our capital expenditures are on budget, our cash flow from operations may continue to decrease materially. If our current production rate decreases significantly, this could also create a material deficiency in cash flow from operations. If any one or all of these events happen, it would be necessary for us to raise additional funds. It is anticipated that additional funds could be raised from one or more of the following sources:
1) We have approximately 375,725 callable common stock purchase warrants outstanding exercisable at a price of $7.50 per share. We are able to call these warrants at any time after our common stock has traded on Nasdaq at a market price equal to or exceeding $10.00 per share for 10 consecutive days which was achieved in July 2000. It is our intent to call all of these warrants at such time, if and when, the cash is needed to fund capital requirements. We will receive proceeds equal to the exercise price times the number of shares which are issued from the exercise of warrants net of commission to the broker of record, if any. We could realize net proceeds of approximately $2,814,500 from the exercise of all of these warrants. There is no assurance that any warrants will be exercised or that we will ever realize any proceeds from the $7.50 warrant calls. However, due to current market conditions and the current price of the Company’s stock, it is not probable that we will call these warrants in the fourth quarter of 2001.
2) We currently have approximately $500,000 of available borrowing capacity under our revolving credit facility.
3) We may seek mezzanine financing, if available, on terms acceptable to us. Mezzanine financing usually involves debt with a higher cost of capital as compared to conventional bank financing. We would seek mezzanine financing in the range of $1,000,000 to $5,000,000. We would seek to use this means of financing in the event that a particular acquisition did not have sufficient proved producing reserve collateral to support a conventional bank loan.
4) We may realize additional cash flow from oil and gas wells to be drilled, if found to be productive. We own working interests in wells that are currently producing and in additional wells, which are presently being completed and equipped for production. We currently estimate that for the fourth quarter of 2001 our production will generate approximately $1.1 million of net cash flow at present commodity prices after deducting lease-operating expenses, general and administrative expenses and interest expense.
If the above additional sources of cash are insufficient or do not materialize on terms acceptable to us, we would expect to reduce the scope of our business activities. If we are unable to fund planned expenditures within a thirty to sixty-day period after a well is proposed for drilling, it may be necessary to: 1) Forfeit our interest in wells that are proposed to be drilled; 2) Farm-out our interest in proposed wells; 3) Sell a portion of our interest in proposed wells and use the sale proceeds to fund our participation for a smaller-than-planned interest; or 4) Reduce general and administrative expenses. The timing of most of our capital expenditures is discretionary. However, in the fourth quarter, we do have material commitments associated with certain of our capital expenditure plans but to date those commitments have been or will be satisfied. We have no material commitments on other capital commitments or operating agreements. Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant. The level of capital expenditures will vary in future periods depending on the success we experience on planned future exploratory drilling activities, gas and oil price conditions and other related economic factors. Accordingly, we have not finalized our estimate of capital expenditures for 2002.
Our long-term goal is to continue the pattern of growing the Company by accumulating oil and gas reserves through acquisition and drilling during the next two to four-year period, and then sell the Company. In the event we cannot raise additional capital, or the industry market is unfavorable, we may have to slow or alter our long-term goal accordingly.
Comparison of Results of Operations
Quarter ended September 30, 2001 Compared to Quarter ended September 30, 2000 We had a reported net loss of ($4,657,047) for the three-month period ended September 30, 2001 compared to net income of $840,441 for the same period ended 2000. Our results of operations for the quarter ended September 30, 2001 included a $6,770,110 ($4,577,837 net of income tax) full cost ceiling impairment. Due to declining natural gas and crude oil prices, the total cost of our U.S. evaluated properties at September 30, 2001 exceeded their net realizable value based on September 30, 2001 prices as required by SEC rules. Please refer to Item 1. FINANCIAL STATEMENTS, Note 4 OIL AND GAS PROPERTIES for further discussion. Excluding the full cost ceiling impairment, we had a net loss of ($79,210) for the three-month period ended September 30, 2001 compared to net income of $840,441 for the same period in 2000. Production volume for the three months ended September 30, 2001 was approximately 60% higher than the same period in 2000 but lower natural gas and crude oil prices, increased operating expenses and higher depletion and depreciation offset the increase in production.
The following table summarizes key items of comparison and their related increase (decrease) for the periods indicated.
In Thousands ................... Quarters Ended Sept 30 $-Increase %-Increase
2001 2000 (Decrease) (Decrease)
----------- --------- -------- ---------
Net income (loss) .............. $ (4,657.0) $ 840.4 $ (5,497.4)
Oil and gas sales .............. 2,398.7 1,967.8 430.9 22%
Field service income ........... 132.6 55.0 77.6 141%
Operating expense .............. 847.7 303.8 543.9 179%
Field service expense .......... 59.9 29.5 30.4 103%
G&A expense ................ 611.2 651.6 (40.4) (6)%
Depletion - Full cost .......... 890.0 110.4 779.6 706%
Depreciation - Field service and
other ....................... 72.2 28.3 43.9 155%
Full cost ceiling impairment ... 6,770.1 -- 6,770.1
Interest expense ............... 203.5 92.5 111.0 120%
Income tax (provision) benefit . 2,230.5 -- 2,230.5
Production:
Natural Gas - Mcf .............. 571.8 414.2 157.6 38%
Crude Oil - Bbl ................ 27.2 7.4 19.8 268%
Natural Gas Equivalent - Mcfe .. 735.0 458.6 276.4 60%
$ per unit:
Ave. gas price - Mcf ........... $ 3.00 $ 4.22 $ (1.22) (29)%
Ave. oil price - Bbl ........... $ 25.06 $ 29.17 $ (4.11) (14)%
Ave. operating expense - Mcfe .. $ 1.15 $ .66 $ .49 74%
Ave. G&A - Mcfe ............ $ .83 $ 1.42 $ (.59) (41)%
For the three months ended September 30, 2001 oil and gas sales increased $430,907, or 22%, from the same period in 2000, to $2,398,684. Increased production of natural gas and crude oil accounted for a $1,243,430 increase in oil and gas sales for the quarter from the same period in 2000. The increase in volume sold for the three-month period ended September 30, 2001, when compared to the same period for 2000, was comprised of a 54% increase in natural gas volume and a 46% increase in crude oil volume. The increased volume was due to the production acquired by Beta in the merger with Red River Energy, LLC on September 1, 2000 (see Item 1. FINANCIAL STATEMENTS, Note 8 DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES) and new wells put on line in the last half of 2000 and first half of 2001 offset partially by lower production volumes associated with a portion of our South Texas shallow Frio wells and West Cameron Block 39 wells. The decrease in the South Texas wells was due to greater than expected natural decline and increased water production. The West Cameron Block 39 wells were undergoing recompletions and operational improvements and returned to production at the end of the quarter. Additionally, lower natural gas prices and crude oil prices for the quarter ended September 30, 2001, when compared to the same period in 2000, resulted in lower natural gas revenues of $700,650 and lower crude oil revenues of $111,874 or a total $812,524 in lower revenues. 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. For the three-month period ended September 30, 2001, approximately 32% of our production was hedged. Hedges cover approximately 35% of our daily average production on an equivalent Mcf basis for the period October 2001 through February 2002. 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 September 30, 2001, a decrease in the average natural gas price realized by the Company of $1.00 per Mcf would result in an approximate $572,000 reduction in net income before income taxes for the quarter. Operating expenses, including production and ad valorem taxes, increased $543,843 or 179%, to $847,679 for the quarter ended September 30, 2001. The increase from the same period in 2000 was due to approximately $492,005 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 $1.44 per equivalent Mcf for the three-month period ended September 30, 2001. This operating cost per equivalent Mcf is significantly higher than the quarterly average for the remaining properties of $.58 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 September 30, 2001 decreased by $40,347 when compared to the same period in 2000. The decrease was mainly due to approximately $281,300 of relocation and moving expense associated with the Company's move in July 2000 and outside services related to the Merger, which were recorded in the three-month period ended September 30, 2000. This reduction was partially offset by increased expenses of approximately $240,000, during the three month period ended September 30, 2001, which included salary and personnel expense related to additional personnel from the Merger, which took place in September 2000 and increased corporate expenses, including rent and corporate insurance expense Depletion and depreciation expense increased $823,451 or 593%, to $962,193 for the three months ended September 30, 2001 from $138,742 for the same period in 2000. Depletion associated with evaluated oil and gas properties comprised $779,520, or 95%, 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 September 30, 2001 compared to the same period ended for 2000 and the associated cost basis, depletion expense increased for the quarter. Due to the significant increase of proved reserves related to Merger in the three-month period ended September 30, 2000, depletion expense on a per Mcf equivalent basis was significantly lower for 2000 when compared to the same period for this year. Depletion expense on a per Mcf equivalent basis for the three months ended September 30, 2001 was $1.21 per Mcf compared to $.24 per Mcf for the same period in 2000. Depreciation expense for the three months ended September 30, 2001 was $72,237 compared to $28,346 for the same period in 2000. The increase was due to gathering assets acquired in the Merger At September 30, 2001, the total capitalized costs for the U.S. evaluated properties full cost pool exceeded the net realizable value of the properties and accordingly an impairment write-down of $6,770,110 was recorded in the three-month period ended September 30, 2001. The impairment was due mainly to the significant decline in the price of natural gas and to a lesser extent the decline in the price of crude oil. The prices used in the determination at September 30, 2001 were $2.20 per Mmbtu for natural gas and $23.50 per barrel for crude oil. The prices used at June 30, 2001 for the impairment test were $3.09 per Mmbtu for natural gas and $26.25 per barrel for crude oil. Since the June 30, 2001 impairment test, the price for natural gas has decreased approximately 29% and the price for crude oil has decreased approximately 10%. There was no comparable charge for the same period in 2000. Interest expense increased 120% for the quarter ended September 30, 2001, compared to the same period 2000 as a result of the debt acquired in the Merger.
Nine Months ended September 30, 2001 Compared to Nine Months ended September 30, 2000
We had a reported net loss of ($3,363,213) for the nine-month period ended September 30, 2001 compared to net income of $664,473 for the same period ended 2000. Our results of operations for the nine months ended September 30, 2001 included a $6,770,110 ($4,777,235 net of income tax) full-cost ceiling impairment as a result of declining natural gas and crude oil prices. At September 30, 2001 the total cost of our U.S. evaluated properties exceeded their net realizable value, based on September 30, 2001 prices, and accordingly a non-cash writedown was recorded as required by SEC rules. However, results from operations, excluding the impairment charge, for the nine-month period ending September 30, 2001 exceeded results from the same period ending in 2000. Net income, excluding the full cost ceiling impairment, for the nine months ending September 30, 2001 was $1,414,022 compared to net income of $664,473 for the same nine-month period in 2000. Higher natural gas and crude oil sales volumes and higher natural gas prices the nine months ended September 30, 2001 were the primary factors for the improved results when compared to the same period for 2000.
The following table summarizes key items of comparison and their related increase (decrease) for the periods indicated.
In Thousands ................. Nine Months Ended Sept.30 $-Increase %-Increase
2001 2000 (Decrease) (Decrease)
---------- --------- -------- --------
Net income (loss) ............ $ (3,482.3) $ 664.5 $ (4,146.8)
Oil and gas sales ............ 10,263.0 3,990.3 6,272.7 157%
Field service income ......... 774.0 55.0 719.0 1,307%
Operating expense ............ 2,440.1 460.0 1,980.1 430%
Field service expense ........ 298.1 29.8 268.3 900%
G&A expense .............. 1,864.3 1,576.3 288.0 18%
Depletion - Full cost ........ 3,512.1 1,276.6 2,235.5 175%
Depreciation - Field service
and other ................. 266.3 34.7 231.6 668%
Full cost ceiling impairment . 6,770.1 -- 6,770.1
Interest expense ............. 706.1 94.5 611.6 647%
Income tax (provision) benefit 1,403.0 -- 1,403.0
Production:
Natural Gas - Mcf ............ 1,820.6 1,064.4 756.2 71%
Crude Oil - Bbl .............. 81.5 9.1 72.4 796%
Natural Gas Equivalent - Mcfe 2,309.7 1,119.0 1,190.7 106%
$ per unit:
Ave. gas price - Mcf ......... $ 4.46 $ 3.50 $ .96 27%
Ave. oil price - Bbl ......... $ 26.39 $ 28.91 $ (2.52) (9)%
Ave. operating expense - Mcfe $ 1.06 $ .41 $ .65 157%
Ave. G&A - Mcfe .......... $ .81 $ 1.41 $ (.60) (43)%
For the nine months ended September 30, 2001 oil and gas sales increased $6,272,728, or 157%, from the same period ended 2000 to $10,263,008. Increased production volume of natural gas and crude oil accounted for 76% of the increase in oil and gas sales for the nine months. Of the increase in sales due to higher production volume, natural gas comprised 56% of the increase while crude oil accounted for the remaining 44%. The increase in the production volume for the nine months ended September 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 nine-month period ended September 30, 2000 resulted in additional revenues of approximately $1,736,796, or 27% of the increase in oil and gas sales. Conversely, lower crude oil prices during this period decreased by approximately 9% resulting in lower revenues of approximately $205,700. 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 approximately 26% of our production on an equivalent Mcf basis for the nine-month period ended September 30, 2001. Based on our natural gas production for the nine months ended September 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 $1,820,600 reduction in net income before income taxes. Operating expenses, including production and ad valorem taxes, increased $1,980,173, or 430%, to $2,440,141 for the nine months ended September 30, 2001. The increased expenses were due to additional operating expenses associated expenses associated with the Merger properties, higher production and severance taxes from increased oil and gas sales and an increase in number of wells put on production during the last half of 2000 and first half of 2001. The average operating expense, including production tax, for the Merger oil and gas properties was approximately $1.35 per equivalent Mcf for the nine-month period ended September 30, 2001. This operating cost per equivalent Mcf is significantly higher than the nine-month average for the remaining properties of $.55 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 nine months ended September 30, 2001 increased approximately $287,937, or 18%, to $1,864,251 compared to $1,576,314 for the same period in 2000. The increase in G&A was due to increased salary and associated personnel expense related to personnel hired in the Merger and outside services, which provide operational accounting services for the properties from the Merger, and overall increase in corporate activity for the nine-month period. Depletion and depreciation expense increased $2,467,119, or 188%, from the same period in 2000 to $3,778,390 for the nine months ended September 30, 2001. Depletion associated with evaluated oil and gas properties comprised $2,235,540, or 91%, 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 nine-month period ended September 30, 2001 compared to the same period ended 2000 and a higher cost basis at September 30, 2001, depletion expense increased. Depletion expense on a per Mcf equivalent basis for the nine months ended September 30, 2001 was $1.52 per Mcf compared to $1.14 per Mcf for the same period in 2000 Depreciation expense, related to other assets, for the nine months ended September 30, 2001 was $266,307 compared $34,729 for the same period in 2000. The increase was due to gathering assets acquired in the Merger. At September 30, 2001, the total capitalized costs for the U.S. evaluated properties full cost pool exceeded the net realizable value of the properties and accordingly an impairment write-down of $6,770,110 was recorded in the three-month period ended September 30, 2001. The impairment was due mainly to the significant decline in the price of natural gas and to a lesser extent the decline in the price of crude oil. The prices used in the determination at September 30, 2001 were $2.20 per Mmbtu for natural gas and $23.50 per barrel for crude oil. The prices used at June 30, 2001 for the impairment test were $3.09 per Mmbtu for natural gas and $26.25 per barrel for crude oil. Since the June 30, 2001 impairment test, the price for natural gas has decreased approximately 29% and the price for crude oil has decreased approximately 10%. There was no comparable charge for the same period in 2000. Interest expense increased for the nine months ended September 30, 2001, compared to the same period 2000 as a result of the debt acquired in the Merger. Income Taxes As of September 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 September 30, 2001, we have a deferred tax liability of $2,133,079. 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 partially mitigate the fluctuations in gas and crude oil prices. We currently have approximately 29% of our gas production hedged through February 2002 and approximately 59% of our crude oil production hedged through March 2002. 2002, based on the September 2001 production rate. 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.
PART II - OTHER INFORMATION Item 1. Legal Proceedings Not applicable. Item 2. Changes in Securities
During the three-month period ending September 30, 2001, the Company realized $12,000 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 $4.50 and were originally issued in 1997 and 1998.
No underwriter was used in the issuance or exercise 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 and the persons who exercised them had full information concerning the business and affairs of the Company and acquired the respective securities 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 There were no matters submitted to the security holders during the quarter ended September 30, 2001.
Item 5. Other Information Not applicable. Item 6. Exhibits and Reports on Form 8-K (a) Exhibit 10.36 West Broussard Exploration Agreement between Pledger Operating Company, Inc. and Beta Oil & Gas, Inc. (http://www.sec.gov/ Archives /edgar/data/1059324/000105932400000042/0001059324-01-500010.txt) (b) Form 8-K dated September 19, 2001 reported Item 5 and Item 7. 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: November 8, 2001 By /s/ Joseph L. Burnett ------------------------ Joseph L. Burnett Chief Financial Officer and Principal Accounting Officer
