UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 10-Q

 

 

 

 

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 ý    No o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

 

As of May 1, 2003, the Registrant had 12,430,807 shares of Common Stock, $.001 par value, outstanding.

 

 

INDEX

 

PART 1 - FINANCIAL INFORMATION
ITEM 1.	Financial Statements
	Condensed Consolidated Balance Sheets as of March 31, 2003 (unaudited) and December 31, 2002
	Condensed Consolidated Statements of Operations for the three months ending March 31, 2003 and March 31, 2002 (unaudited)
	Condensed Consolidated Statements of Cash Flows for the three months ending March 31, 2003 and March 31,2002 (unaudited)
	Supplemental Disclosure of Noncash Investing and Financing Activities for the three months ending March 31, 2003 and March 31, 2002 (unaudited)
	Notes to Condensed Consolidated Financial Statements
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Disclosure Regarding Forward-Looking Statements
	General
	Liquidity and Capital Resources
	Plan of Operation for 2003
	Comparison of Results of Operations for the three months ended March 31, 2003 and 2002
	Income Taxes
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk
ITEM 4.	Controls and Procedures
PART II. - OTHER INFORMATION
ITEM 2.	Changes in Securities and Use of Proceeds
ITEM 5.	Other Information
ITEM 6.	Exhibits and Reports on Form 8-K
Signatures
Certifications

 

2

 

PART I

ITEM 1.  FINANCIAL STATEMENTS

BETA OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		MARCH 31, 2003			DECEMBER 31, 2002
		(Unaudited)
CURRENT ASSETS:
Cash		$	866,769		$	927,313
Accounts receivable
Oil and gas sales		2,481,413			1,676,935
Other		310,304			149,243
Income tax prepaid		23,209			52,115
Prepaid expenses		116,237			187,818
Total current assets		3,797,932			2,993,424
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties		72,093,852			70,907,441
Unevaluated properties		4,404,225			4,582,605
Less – accumulated amortization of full cost pool		(36,220,603		)	(35,133,445		)
Net oil and gas properties		40,277,474			40,356,601
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system		1,507,177			1,507,177
Support equipment		221,413			221,413
Other		246,586			215,302
Less – accumulated depreciation		(671,106		)	(616,865		)
Net other operating property and equipment		1,304,070			1,327,027
OTHER ASSETS		10,839			76,208
TOTAL ASSETS		$	45,390,315		$	44,753,260
CURRENT LIABILITIES:
Current portion of long-term debt		$	14,251		$	70,831
Accounts payable, trade		1,778,769			1,909,226
Dividends payable		110,256			112,707
Futures transaction hedge liability		211,690			702,417
Other accrued liabilities		311,304			275,290
Total current liabilities		2,426,270			3,070,471
LONG-TERM DEBT, less current portion		13,634,652			13,634,652
ASSET RETIREMENT OBLIGATION (NOTE 3)		921,949			—
COMMITMENTS AND CONTINGENCIES  (NOTE 6)
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,272 issued and outstanding at March 31, 2003 and December 31, 2002.  Liquidation preference at March 31, 2003 is $5,696,496.		604			604
Common stock, $.001 par value; 50,000,000 shares authorized; 12,446,072 issued at March 31, 2003 and December 31, 2002, 12,430,807 and 12,440,057 shares outstanding at March 31, 2003 and December 31, 2002, respectively		12,447			12,447
Additional paid-in capital		51,919,964			51,917,235
Treasury stock, at cost; 15,265 shares and 6,015 shares reacquired at March 31, 2003 and December 31, 2002, respectively		(35,264		)	(28,153		)
Accumulated other comprehensive loss		(211,690		)	(702,417		)
Accumulated deficit		(23,278,617		)	(23,151,579		)
Total stockholders’ equity		28,407,444			28,048,137
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	45,390,315		$	44,753,260

 

The accompanying notes are an integral part of these condensed consolidated financial statements

 

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BETA OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2003			2002
REVENUES:
Oil and gas sales		$	2,893,347		$	2,259,513
Field services		207,888			83,739
Total revenue		3,101,235			2,343,252
COSTS AND EXPENSES:
Lease operating expense		783,818			738,783
Field services		51,837			41,323
General and administrative		813,811			475,344
Depreciation and amortization expense		1,335,068			1,155,610
Total costs and expenses		2,984,534			2,411,060
INCOME (LOSS) FROM OPERATIONS		116,701			(67,808)
OTHER INCOME (EXPENSE):
Interest expense		(135,995		)	(140,611		)
Interest income		873			2,188
Total other income (expense)		(135,122		)	(138,423		)
LOSS BEFORE INCOME TAX		(18,421		)	(206,231		)
INCOME TAX BENEFIT		—			—
LOSS BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		(18,421		)	(206,231		)
CUMULATIVE EFFECT ON PRIOR YEARS FROM ADOPTION OF FASB STATEMENT NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATION (SEE NOTE 3)		1,640			—
NET LOSS		(16,781		)	(206,231		)
PREFERRED DIVIDENDS		(110,256		)	(110,256		)
NET LOSS APPLICABLE TO COMMON SHAREHOLDERS		$	(127,037	)	$	(316,487	)
BASIC NET LOSS PER COMMON SHARE		$	(.01	)	$	(.03	)
DILUTED NET LOSS PER COMMON SHARE		$	(.01	)	$	(.03	)
COMPREHENSIVE INCOME (LOSS):
NET LOSS		$	(16,781	)	$	(206,231	)
OTHER COMPREHENSIVE INCOME:
Reclassification of realized loss (gain) on qualifying cash flow hedges		1,031,009			197,247
Unrealized gain (loss) on qualifying cash flow hedges		(540,282		)	(985,046		)
TOTAL COMPREHENSIVE INCOME (LOSS)		$	473,946		$	(994,030	)

 

The accompanying notes are an integral part of these condensed consolidated financial statements

 

4

 

BETA OIL & GAS, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss before cumulative effect		$	(18,421	)	$	(206,231	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		1,335,068			1,155,610
Compensation expense from stock options		2,728			—
Change in operating assets and liabilities:
Accounts receivable		(965,539		)	(113,394		)
Income tax receivable		28,906			560
Prepaid expenses		71,581			5,531
Accounts payable, trade		(130,457		)	(490,723		)
Other accrued expenses		36,014			(133,833		)
Accretion of asset retirement obligation		13,703			—
Asset retirement obligation incurred		(5,314		)	—
Net cash provided by operating activities		368,269			217,520
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property expenditures		(286,499		)	(1,194,311		)
Proceeds received from sale of oil and gas properties		—			879,501
Change in other assets		65,369			28,575
Gas gathering and other equipment expenditures		(31,284		)	(13,818		)
Net cash used in investing activities		(176,899		)	(300,053		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from premiums payable		—			33,902
Repayment of premiums payable		(53,178		)	(20,015		)
Repayment of notes payable		(3,402		)	(3,116		)
Offering costs		—			14,706
Dividends paid		(112,708		)	(112,709		)
Acquisition of treasury stock		(7,111		)	—
Net cash used in financing activities		(176,399		)	(87,232		)
NET DECREASE IN CASH AND  CASH EQUIVALENTS		(60,544		)	(169,765		)
CASH AND CASH EQUIVALENTS, at beginning of period		927,313			556,199
CASH AND CASH EQUIVALENTS, at end of period		866,769			386,434
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest		123,482			92,781
Income taxes		—			—
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Fair value of treasury stock issued for:
Oil and gas properties		$	—		$	170,767

 

The accompanying notes are an integral part to these condensed consolidated financial statements

 

5

 

FINANCIAL STATEMENTS

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

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 in the United States 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 March 31, 2003 and the results of its operations and cash flows for the three months ended March 31, 2003 and 2002.  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 in the United States have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission.  The December 31, 2002 consolidated balance sheet was derived from audited financial statements, but does not include all disclosures required by generally accepted accounting principles in the United States.  The accompanying financial statements should be read in conjunction with the audited financial statements as contained in our Annual Report on Form 10-K and Form 10-KA for the fiscal year ended December 31, 2002 that were filed March 31, 2003 and April 28, 2003, respectively.

 

Note 2.                                     OIL AND GAS PROPERTIES:

 

The Company accounts for its oil and gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized.  All general corporate costs are expensed as incurred.  In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded.  Amortization of evaluated oil and gas properties is computed on the unit of production method based on all proved reserves on a country-by-country basis.  Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate basis.  The net capitalized costs of evaluated oil and gas properties are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues discounted based on current economic and operating conditions discounted at 10%.  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 a minimum on an annual basis.  Unevaluated leasehold costs, including brokerage costs, are individually assessed quarterly based on the remaining term of the primary leasehold.

 

With the volatility of commodity prices and the possibility of exploration expenditures resulting in no significant proved reserve additions, it is possible that future impairments of oil and gas properties could occur.  The price measurement date is on the last day of the quarter or year-end as required by SEC rules.

 

Note 3.                                     ASSET RETIREMENT OBLIGATION

 

Effective January 1, 2003, the Company adopted SFAS 143 “Asset Retirement Obligations” which establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial

 

6

 

statement disclosures.  SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.  The Company has an obligation to proportionately share in the plugging and abandonment costs associated with the oil and gas properties in which it owns a working interest.  This liability represents the Company’s asset retirement obligation.  The Company has estimated the expected cash flow obligation associated with the plugging and has discounted this amount using a credit-adjusted, risk-free interest rate of 6%.  The Company also adjusted the carrying value of its oil and gas properties by this amount and conversely adjusted the associated accumulated depletion by the estimated depletion impact reduced by the estimated salvage value from the abandoned assets.  The transition adjustment resulting from the adoption of SFAS 143, and reported as a cumulative effect of a change in accounting principle, was an increase to income of $1,640.  At January 1, 2003, the Company recorded an asset retirement obligation of $913,560.

 

During the three months ended March 31, 2003, the Company recorded $13,703 in accretion expense with a corresponding increase to the asset retirement obligation and recorded a settlement on the asset retirement obligation of $5,314.

 

Note 4                                        STOCKHOLDERS’ EQUITY:

 

Options

On January 1, 2003, the Company adopted FASB Statement No. 123 Accounting for Stock-Based Compensation (FASB 123) and related interpretations in accounting for its employee and director stock options and will apply the fair value based method of accounting to such options.  Under FASB Statement No. 148 Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to FASB 123, certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation if adopted in a fiscal year beginning before December 16, 2003.  The Company will use the prospective method which will apply prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted.

 

At March 31, 2003, the Company had one stock-based employee compensation plan.  Prior to January 1, 2003, the Company accounted for that plan and any other option or warrant issuances to employees and directors under the recognition and measurement provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and related Interpretations.  No stock-based employee compensation cost is reflected in the net loss for the three months ended March 31, 2002, as all options or warrants granted had an exercise price equal to or greater than the market value of the underlying common stock on the date of grant.  As previously stated, on January 1, 2003 the Company adopted the fair value recognition provisions of FASB 123 prospectively to all employee awards granted, modified or settled after January 1, 2003.  Awards vest over periods ranging from one to three years.  Therefore, the cost related to stock-based compensation included in the determination of income for the three month periods ended March 31, 2003 and 2002 is less than that which would have been recognized if the fair value method had been applied to all awards since the original effective date of FASB 123.  The following table illustrates the effect on net income and earnings per share if the fair value based method had been applied to all outstanding and unvested awards in each period.

 

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		For the Quarters Ended March 31,
		2003			2002
Net loss applicable to common shareholders as reported		$	(127,037	)	$	(316,487	)
Add: Stock-based compensation expense included in reported net loss		2,728			—
Deduct: Total stock-based compensation expense determined under fair value method for all awards		(45,088		)	(71,078		)
Pro forma net loss		$	(169,397	)	$	(387,565	)
Earnings per share:
Basic – as reported		$	(.01	)	$	(.03	)
Basic – pro forma		$	(.01	)	$	(.03	)
Diluted – as reported		$	(.01	)	$	(.03	)
Diluted – pro forma		$	(.01	)	$	(.03	)

 

The Company issued 135,000 non-qualified stock options to attract certain new employees during the quarter ended March 31, 2003.  These options will equally vest over a three-year period beginning in 2004.  The options have exercise prices ranging from $.85 to $.93 per share and will expire in 2013.  The Company recognized compensation expense of $2,729.

 

Treasury Stock

Effective January 14, 2003, the Company’s Board of Directors authorized a stock repurchase program for up to an aggregate of 100,000 shares of the Company’s common stock.  Purchases may be made in the open market, at prevailing market prices, or in privately negotiated transactions from time to time, and will depend on market conditions, business opportunities and other factors. Any purchases are expected to be made in compliance with the safe harbor provisions of Rule 10b-18 promulgated by the Securities and Exchange Commission under the Securities and Exchange Act of 1934.

 

During the three month period ended March 31, 2003, the Company purchased 9,250 shares for $7,111, or $.77 per share.  At March 31, 2003, the Company held 15,265 treasury shares with a market value of $10,686, or $.70 per share.

 

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Note 5.                                     NET LOSS PER COMMON SHARE:

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2003			2002
Basic:
Net loss		$	(16,781	)	$	(206,231	)
Less: Preferred dividends		(110,256		)	(110,256		)
Net loss applicable to common shareholders		$	(127,037	)	$	(316,487	)
Weighted average number of common shares		12,438,310			12,390,935
Basic earnings (loss) per share		$	(.01	)	$	(.03	)
Diluted:
Net loss applicable to common shareholders		$	(127,037	)	$	(316,487	)
Add:  Preferred dividends		—			—
Net loss for diluted earnings (loss) per share		$	(127,037	)	$	(316,487	)
Weighted average number of Common shares		12,438,310			12,390,935
Common stock equivalent shares representing shares issuable upon exercise of stock options		Antidilutive			Antidilutive
Common stock equivalent shares representing shares issuable upon exercise of warrants		Antidilutive			Antidilutive
Common stock equivalent shares representing shares “as-if” conversion of preferred shares		Antidilutive			Antidilutive
Weighted average number of shares used in calculation of diluted loss per share		12,438,310			12,390,935
Diluted loss per share		$	(.01	)	$	(.03	)

 

The following common stock equivalents were not included in the computation for diluted loss per share because their effects were antidilutive.

 

 

Note 6.                                     CONTINGENCIES

 

In September 2001, the Company participated with a 62.5% interest in the drilling of the Dore #1, Live Oak Prospect located in Vermilion Parish, Louisiana.  The well, which was drilled by a third-party contract drilling company, was deemed non-commercial and plugged and abandoned.  During plugging operations, drilling fluid was discovered surfacing away from the well location indicating an integrity issue with the well bore.  All regulatory agencies were notified and the Company, as operator of the well, engaged a third party to perform a groundwater investigation to determine the extent of groundwater contamination, if any.  Preliminary findings indicate there was no substantial groundwater contamination and a recommendation will be made to the proper regulatory agencies requesting that no further assessment be required.  The

 

9

 

estimated cost for the investigation is approximately $365,000 and is covered by the Company’s pollution insurance coverage.

 

Note 7.                                     DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

 

Natural Gas – During the quarter ended March 31, 2003, the Company settled certain outstanding commodity price hedging contracts, as set forth below, that covered a portion of its natural gas production during this period.  The hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for either the last three trading days or the last trading day of a particular contract month.  The Company uses a combination of collar and swap arrangements to hedge its natural gas production.  The collar arrangements are costless and no net premium is received in cash or as a favorable rate.

 

 

For the contracts settled during the three months ended March 31, 2003 and 2002, the Company had realized losses of ($849,225) and ($129,121), respectively.  The impact of the natural gas hedges reduced the Company’s average natural gas price received for the three months ended March 31, 2003 and 2002 by $1.86 per Mcf and $.22 per Mcf, respectively.  Based on the actual natural gas production for the three months ended March 31, 2003, approximately 60% of the Company’s natural gas production was hedged for this period.

 

At March 31, 2003, the outstanding hedge contracts, as set forth below, had a negative fair market value of $172,771 and accordingly the Company recorded a derivative liability for such amount.  The fair market value is based on the NYMEX futures contract price for the outstanding contract months at March 31, 2003.  Based on the average daily natural gas production for the three months ended March 31, 2003, approximately 36% of the Company’s production is hedged for the periods shown below in the table.

 

 

Crude Oil – During the quarter ended March 31, 2003, the Company had outstanding commodity price hedging contracts as set forth below covering a portion of its 2003 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.  The Company uses collar arrangements to hedge its crude oil production.  The collar arrangements are costless and no net premium is received in cash or as a favorable rate.

 

10

 

 

For the contracts settled during the three months ended March 31, 2003 and 2002, the Company had realized losses of ($181,784) and ($68,126), respectively.  The impact of the crude oil hedges reduced the Company’s average crude oil price received for the three months ended March 31, 2003 and 2002 by $6.21 per Bbl and $1.71per Bbl, respectively.  Based on the actual crude oil production for the three months ended March 31, 2003, approximately 51% of the Company’s crude oil production was hedged for this period.

 

At March 31, 2003, the outstanding hedge contracts, as set forth below, had a negative fair market value of $38,919 and accordingly the Company recorded a derivative liability for such amount.  The fair market value is based on the NYMEX futures contract price for the outstanding contract months at March 31, 2003.  Based on the average daily crude oil production for the three months ended March 31, 2003, approximately 25% of the Company’s production is hedged for the periods shown below in the table.

 

 

Note 8.                                     SUBSEQUENT EVENTS

 

Subsequent to March 31, 2003, the Company was in the process of renewing and extending its current credit facility which will maintain the current borrowing capacity of $14,500,000.  The Company currently has $13,634,652 outstanding against the borrowing base.  The maturity date of the current credit agreement will be extended to April 1, 2005.

 

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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 March 31, 2003 and December 31, 2002 and the results of operations for the three-month periods ended March 31, 2003 and 2002.

 

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:

 

•                  Estimates of proved reserve quantities and net present values of those reserves

•                  Reserve potential

•                  Business strategy

•                  Capital expenditures – amount and types

•                  Expansion and growth of our business and operations

•                  Expansion and development trends of the oil and gas industry

•                  Production of oil and gas reserves

•                  Exploration prospects

•                  Wells to be drilled, and drilling results

•                  Operating results and working capital

•                  Plan of operation for 2003

 

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 more fully described 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

Due to global events, weather conditions, domestic production decline and signs of a slowly improving economy, commodity prices have strengthened since the first quarter of 2002.  The current natural gas storage level remains below the five-year average.  We continue to be optimistic about the longer-term outlook for natural gas.   However, the overall environment for commodity pricing is very volatile and can be materially affected, favorably or unfavorably, by such factors as imports/exports, weather trends, power generation and industrial demands.  Natural gas drilling activity has increased during the last quarter of 2002 and early 2003 but sustained activity will be dependent on long-term price stability.

 

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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/options and proceeds from public and private stock offerings.

 

The following table represents the sources and uses of cash for the periods indicated.

 

		For the three months ended Mar. 31,
		2003			2002
Beginning cash balance		$	927,313		$	556,199
Sources of cash:
Cash provided by operations		359,880			217,520
Cash provided by sales of oil & gas properties and equipment		—			879,501
Cash provided by change in other assets		65,369			28,575
Total sources of cash including cash on hand		1,352,562			1,681,795
Uses of cash:
Oil and gas expenditures, net of prepaid drilling advances		(286,499		)	(1,194,311		)
Other asset expenditures		(31,284		)	(13,818		)
Cash used in financing activities		(168,010		)	(87,232		)
Total uses of cash		(485,793		)	(1,295,361		)
Ending cash balance		$	866,769		$	386,434

 

Our working capital was a surplus of $1,371,662 at March 31, 2003 compared to a deficit of ($262,554) at March 31, 2002 and a deficit of ($77,047) at December 31, 2002.  The significant increase in our working capital and liquidity at March 31, 2003, when compared to March 31, 2002, was due to lower oil and gas capital expenditures and higher natural gas and crude oil prices in the last twelve months.  At March 31, 2003, we had a futures derivative liability, associated with that portion of our future production volume currently hedged, of $211,690 compared to futures derivative liabilities at March 31, 2002 and December 31, 2002 of $640,867 and $702,417.  The futures transaction hedge liability represents the potential unrealized reduction in our future oil and gas revenue based on the current outstanding derivative contracts.  The estimate is based on the NYMEX natural gas and crude oil futures prices in effect at March 31, 2003 and may vary materially from month to month.

 

Our principal source of short-term liquidity is from operating cash flow.  Our short-term liquidity and working capital should steadily increase in the remainder of 2003.  Should natural gas and crude oil prices decrease materially, our current operating cash flow would decrease and would impede our liquidity and working capital growth.

 

Our borrowing base capacity under the current credit facility, which was acquired through the Red River Energy acquisition, is not a material source of capital.  Historically we have not used credit facilities for a source of funds in our drilling or leasing activity.  Should proved developed reserves not materially increase and/or pricing materially declines, our borrowing base may be reduced below the amount currently borrowed and outstanding under this facility.  If this event occurs we would be obligated to pay down the outstanding amount to the re-determined borrowing capacity. We would rely on cash flow from operations and funds generated from the sale of unevaluated or proved undeveloped prospects to make this pay down. It is possible that we would have to sell some non-core assets as well in order to meet this obligation.  The current credit agreement, which has a maturity date of March 15, 2004, is in the process of being renewed and extended.  The renewal will extend the maturity date to April 1, 2005 and maintain the current borrowing capacity at $14,500,000.  Currently, a balance of $13,634,652 is outstanding against the borrowing base.  At March 31, 2003, our effective interest rate, which is LIBOR base rate plus 2.2%, was approximately 3.5%.

 

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Long Term Liquidity and Capital Resources

We have no material long-term commitments associated with our capital expenditure plans 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 have with our exploratory drilling activities in future periods, gas and oil price conditions and other related economic factors.  The following tables show our contractual obligations and commitments.

 

		Payments Due by Period
Contractual Obligations		Total			Less than 1 year			1-3 years			4-5 years			After 5 years
Long – Term Debt (1)		$	13,648,903		$	14,251		$	13,634,652		$	—		$	—
Operating Leases (2)		139,627			111,769			27,858			—			—
Total cash obligations		$	13,788,530		$	126,020		$	13,662,510		$	—		$	—

 

(1)                         $13,634,652 is related to our current credit agreement with a commercial bank.  Subsequent to March 31, 2003, our revolving credit agreement was in the process of being renewed and extended to April 1, 2005.  Our current collateral borrowing base of $14,500,000 will remain unchanged.

(2)                         Represents amounts due under current operating lease agreements including the office rental agreement.

 

		Amount of Commitment Expiration per Period
Other Commercial Commitments		Total			Less than 1 year			1-3 years		4-5 years		After 5 years
Standby letters of credit		$	108,500		$	108,500		—		—		—

 

We currently have no sources of liquidity or financing that are provided by off-balance sheet arrangements or transactions with unconsolidated, limited purpose entities.

 

Accounting Policies

We rely on certain accounting policies in the preparation of our financial statements.  Certain judgments and uncertainties affect the application of such policies.  The “critical accounting policies” which we use are as follows:

 

•      Use of estimates

•      Oil and gas properties

•      Derivative instruments and hedging activity

•      Concentration of credit risk

 

Certain accounting principles are employed in the adherence and implementation of these policies along with management judgments.  We will address each policy and how certain judgments and/or uncertainties could materially impact these policies.

 

Use of Estimates - The preparation of the our consolidated financial statements in conformity with generally accepted accounting principles requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period.  The estimates include oil and gas reserve quantities, which form the basis for the calculation of amortization and impairment of oil and gas properties.  We emphasize that reserve estimates are inherently imprecise and that estimates of more recent discoveries are more imprecise than those for properties with long production histories. Actual results could materially differ from these estimates. Volatility in commodity prices also impacts reserve estimates since future revenues from production may decline significantly if there is a material decrease in natural gas and/or crude oil prices from the previous reserve estimation date, which is at each quarter end.

 

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Oil and gas properties - We account for our oil and gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”).  Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized.  All general corporate costs are expensed as incurred.  In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded.  Amortization of evaluated oil and gas properties is computed on the unit of production method based on all proved reserve quantities, on a country-by-country basis.  The net capitalized costs of evaluated oil and gas properties (full cost ceiling limitation) are not to exceed their related estimated future net revenues discounted at 10%, and the lower of cost or estimated fair value of unevaluated properties, net of tax considerations. Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate basis.  Unevaluated leasehold costs, including brokerage costs, are individually assessed quarterly based on the remaining primary term of the leasehold.  For the three months ended March 31, 2003 unevaluated leasehold costs of $230,110 were transferred to U.S. evaluated costs, or the full cost pool.  For the remaining costs, which include seismic and geological and geophysical, we estimate reserve potential for the unevaluated properties using comparable producing areas or wells and risk adjust that estimate by 50-75%.  As mentioned previously in Use of Estimates, reserve estimations are more imprecise for new or unevaluated areas.  Consequently, should certain geological conditions or factors exist, such as reservoir depletion, reservoir faulting, reservoir quality etc., but unknown to us at the time of our assessment, a materially different result could occur.

 

Derivative instruments and hedging activity – We use derivatives in a limited manner to protect against commodity price volatility.  Effectively, we sell a portion of our natural gas and crude oil based on a NYMEX based price with a set floor (bottom) and ceiling (top) price or a range.  Our derivatives are 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 contracts consist of cash flow hedge transactions which hedge the possible variability of cash flow related to a forecasted transaction.  Changes in the fair value of these derivative instruments are recorded in other comprehensive income and reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item.  The fair value of these contracts may vary materially with the fluctuations of natural gas and crude oil prices.  However, the fluctuation in fair value will be offset by the actual value received from the hedged volume.

 

Stock Option Compensation – On January 1, 2003, we adopted FASB Statement No. 123 Accounting for Stock-Based Compensation (FASB 123) and related interpretations in accounting for our employee and director stock options and will apply the fair value based method of accounting to such options.  Under FASB Statement No. 148 Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to FASB 123, certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation if adopted in a fiscal year beginning before December 16, 2003.  We will use the prospective method which will apply prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted.

 

Concentration of credit risks - Credit risk represents the accounting loss that would be recognized at the reporting date if counter parties failed completely to perform as contracted.  Concentrations of credit risk (whether on or off balance sheet) that arise from financial instruments exist for groups of customers or counterparties when they have similar economic characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions.  We operate in one segment, the oil and gas industry.  A geographic concentration exists because Beta’s customers are generally located within the Central United States.  Financial instruments that subject us to credit risk consist principally of oil and gas sales, which are based solely on short-term purchase contracts from various customers with related accounts receivable subject to credit risk.  However, we do have certain properties, such as WEHLU, that are “captive” to one natural gas purchaser due to the location of the production and lack of alternate sources of purchasers.  In this particular instance, Duke Energy is the natural gas purchaser.

 

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Plan of Operation for 2003

 

During the first quarter of 2003, we announced a successful well in our East unit of the West Broussard Prospect, which is located in the Broussard Field in Lafayette Parish, Louisiana.   The M. A. Failla No. 1 reached total depth on March 10, 2003.  A production liner was run and the well was completed with a final test rate of 8.7 million cubic feet per day with 274 barrels of condensate per day.  Currently, construction and installation of the production facilities and sales pipeline are underway and we anticipate first sales of natural gas to commence by July 1, 2003.  We have a 4.8% working interest in the well, increasing to approximately 10% working interest after well payout.

 

A 3-D seismic survey, which will assist in further delineation of the development in the area, is in progress and should be completed within 45 days.  The 3-D seismic data, combined with the production history and subsurface information from the M.A. Failla No. 1 may support development of that portion of the field, the West unit, where we have a larger working interest.  In accordance with our agreement that is in place with an industry partner, should that partner elect to drill a well in the West unit we would receive $1.3 million.  We would have an approximate 10% working interest in the West unit well, increasing to approximately 20% working interest after well payout.

 

For the year 2003, we expect to fund our capital requirements from net cash flow from operations (after general and administrative expense and interest expense).

 

We project our 2003 capital expenditure to be approximately $3 million.  The areas and amounts of concentration for the capital program will be:

 

•                  West Edmond Hunton Lime Unit, Oklahoma - $1.5 million

•                  Lapeyrouse Field, Terrebonne Parish, Louisiana - $.6 million

•                  West Broussard Prospect, Lafayette Parish, Louisiana - $.3 million

•                  Lake Boeuf Prospect, Lafourche Parish, Louisiana - $.2 million

•                  McIntosh County, Oklahoma - $.1 million

•                  TCM, Tulsa County, Oklahoma - $.1 million

•                  Other - $.2 million

 

We are projecting our cash flows from operations to be approximately $5.5 million based on an average natural gas price of $4.46 per Mcf and an average oil price of $25.29 per barrel and average net daily production of 7.1 MMcfe.  Any proceeds from the sale or reduction of our working interests in certain unevaluated prospects are not considered in our cash flow projections.  As with any projection, the timing and amounts can vary.  Generally, funds must be advanced within thirty days or less after our election to participate in the drilling of a well.

 

Our planned capital expenditures and/or administrative expenses could exceed those amounts budgeted and could exceed our cash from all sources.  While our projected cash expenditures may be as projected, cash flow from operations could be unfavorably impacted by lower-than-projected commodity prices and/or lower than projected production rates.  Conversely, higher-than-projected commodity prices would favorably impact our projected cash flow from operations.   If our expected cash flow is less than projected it may be necessary to raise additional funds.   Possible additional sources of cash could be provided from the following:

 

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 our stock, it is not probable that we will call these warrants in 2003.

 

2)              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 or project did not have sufficient proved producing reserve collateral to support a conventional bank loan.

 

3)              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 currently drilling or scheduled to be drilled in 2003.  Additional cash flow from those wells that are drilling or scheduled to be drilled in 2003 is not considered in our current projection.

 

If the above additional sources of cash are insufficient or are unavailable on terms acceptable to us, we will be compelled 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;

 

16

 

2)              Farm-out our interest in proposed wells;

 

3)              Sell a portion of our interest in the proposed wells and use the sale proceeds to fund our participation for a lesser interest; or

 

4)              Reduce general and administrative expenses.

 

Should our future projected capital expenditures be reduced by lower sources of cash flow or  cash requirements for reduction of our credit facility, our potential growth rate from our exploitation and exploration activities could be materially impacted.  An alternative action to maintain our growth potential would be the acquisition of existing reserves with the use of debt and equity instruments.

 

Our long-term goal is to grow the Company by accumulating oil and gas reserves through exploitation of our existing assets, acquisitions and/or exploratory drilling.  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.  Should we achieve our long-term goal and an acceptable value for our shareholders is recognized over the next two to three years, selling a portion or all of the Company is a possibility.

 

These are forward looking statements that are based on assumptions, which in the future may not prove to be accurate.  Although we believe that the expectations reflected in such forward looking statements are based on reasonable assumptions, we can give no assurance that our expectations will be achieved.

 

17

 

Comparison of Results of Operations

Quarter ended March 31, 2003 and Compared to Quarter ended March 31, 2002

We had a net loss of ($18,421) for the quarter ended March 31, 2003 compared to a net loss of ($206,231) for the same period ended 2002.  Higher natural gas and crude oil prices for the quarter ended March 31, 2003 when compared to the same quarter for 2002 contributed to the lower net loss for the quarter ended 2003, somewhat offset by a decrease in our oil and gas production during the first quarter of this year compared with last year.

 

The following table summarizes key items of comparison and their related increase (decrease) for the periods indicated.

 

		Quarter Ended March 31						$ - Increase (Decrease)			% - Increase (Decrease)
In Thousands		2003			2002
Net income (loss)		$	(16.8	)	$	(206.2	)		189.4		92	%
Oil and gas sales		2,893.3			2,259.5			633.8			28	%
Field service income		207.9			83.7			124.2			148	%
Lease operating expense		566.8			620.9			(54.1		)	(9	)%
Production tax		217.0			117.9			99.1			84	%
Field service expense		51.8			41.3			10.5			25	%
G&A expense		813.8			475.3			338.5			71	%
Depletion – Full cost		1,280.8			1,102.8			178.0			16	%
Depreciation – Field service and other		54.2			52.8			1.4			3	%
Interest expense		136.0			140.6			(4.6		)	(3	)%
Production:
Natural Gas – Mcf		454.5			574.8			(120.3		)	(21	)%
Crude Oil – Bbl		29.2			39.9			(10.7		)	(27	)%
Natural Gas Equivalent – Mcfe		630.0			814.2			(184.2		)	(23	)%
$ per unit:
Ave. gas price – Mcf		$	4.71		$	2.51		$	2.20		88	%
Ave. oil price – Bbl		$	25.72		$	20.55		$	5.17		25	%
Ave. operating expense – Mcfe		$	.90		$	.76		$	.14		18	%
Ave. production tax expense – Mcfe		$	.34		$	.14		$	.20		143	%
Ave. G&A – Mcfe		$	1.29		$	.58		$	.71		122	%
Ave. Depl. – Full cost – Mcfe		$	2.03		$	1.35		$	.68		50	%

 

For the quarter ended March 31, 2003, oil and gas sales increased $633,835 or 28%, from the same quarter ended 2002, to $2,893,347.  The increase for the quarter was a direct result of higher natural gas and crude oil prices.  Lower natural gas inventory levels and normal to above-normal winter demand in the quarter contributed significantly to the higher natural gas prices.  Crude oil prices were affected by lower national storage levels and supply uncertainty due to global events.  The higher commodity prices resulted in an increase in oil and gas revenues of $1,153,334, with higher natural gas prices comprising 87% of the increase.  However, lower natural gas and crude oil production for the quarter ended March 31, 2003, as compared to the same quarter in 2002, partially offset this increase.  Our natural gas and crude oil production was 23% lower, on an Mcf equivalent basis when compared to the same quarter in 2002.  Our lower natural gas and crude oil production is primarily due to natural production decline associated with our South Texas, Brookshire and Lapeyrouse properties.  Lower production volumes resulted in lower oil and gas sales of $519,499, with natural gas production volume comprising 58% of the decrease and crude oil production comprising the remaining 42% of the decrease.

 

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 57% of our production on an equivalent Mmbtu basis for the quarter ended March 31, 2003.  For the quarter ended March 31, 2003, the average sales price received for our natural gas was reduced by approximately $1.86 per Mcf from our natural gas hedges and the average sales price received for

 

18

 

our crude oil was reduced by approximately $6.21 per Bbl from our crude oil hedges.  For further discussion please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.

 

Operating expenses, excluding production taxes, decreased $54,054 or 9%, to $566,845 for the quarter ended March 31, 2003 compared to the same period for 2002.  The decrease was primarily due to lower operating expense associated with the Brookshire Dome area and the 2002 divestment of certain low margin non-core properties.

 

Production tax expense increased $99,089, or 84%, for the quarter ended March 31, 2003 as compared to the same quarter ended in 2002, due to higher natural gas and crude oil prices.  Production taxes are generally assessed as a percentage of gross oil and/or natural gas sales.

 

General and administrative expense for the three months ended March 31, 2003 increased $338,467 or 71%, to $813,811 compared to $475,344 for the same period in 2002.  The increase was due primarily to a $250,000 deferred signing bonus related to hiring of a new executive in late 2002, increased outside services related to engineering and lower general and administrative expense reimbursement from non-operated parties with interests in our operated properties.

 

Depletion and depreciation expense increased $179,458, or 16%, from the same period in 2002 to $1,355,068 for the three months ended March 31, 2003.  Depletion associated with evaluated oil and gas properties comprised $178,019, or 99%, 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.  Due primarily to a decrease in our December 31, 2002 proved reserves related to our West Broussard prospect, our per Mcfe depletion rate for the three months ended March 31, 2003 was $2.03 compared to $1.35 for the same period in 2002.  For the three months ended March 31, 2003, depreciation expense related to other assets increased $1,439 from the same period in 2002 to $54,241.  The increase was related to the depreciation expense associated with the gathering assets, which is calculated on a “unit of revenue” method.  The “unit of revenue” method amortizes the capitalized costs associated with the gathering assets based on the ratio of gross actual revenues for the current period to the total remaining gross revenues for the gathering assets.  Therefore, the higher gross gathering revenues for the three months ended March 31, 2003 resulted in higher depreciation expense for the period.

 

Interest expense decreased for three months ended March 31, 2003, compared to the same period 2002, as a result of lower interest rates partially offset by $13,703 of accretion expense associated with our asset retirement obligation. There was no comparable expense in 2002.

 

Income Taxes

As of March 31, 2003, we had Federal net operating loss carryforwards of approximately $20,771,000, which expire in the years 2012 through 2022.  Utilization of the net operating loss carryforwards may be limited in the event a 50% or more change of ownership occurs within a three-year period.  Additionally, other factors may limit the net operating loss carryforwards.  As of March 31, 2003, we had no deferred taxes.

 

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.  Based on the average production rate for the three months ended March 31, 2003, we have approximately 36% of our future natural gas production hedged through August 2003 and 25% of our future crude oil production hedged through September 2003 (For further information, please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES).  The counterparty to our hedging agreements is a commercial bank.  The remainder of our production is not hedged and we may continue to experience wide fluctuations in oil and gas revenues as a result.  We are also exposed to market risk related to adverse changes in interest rates.  Our outstanding debt under our current credit facility bears interest at a LIBOR based rate plus 2.20%.  Volatility in the future 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.

 

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ITEM 4.  CONTROLS AND PROCEDURES

 

Within 90 days prior to the date of this Form 10-Q, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures.  Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures  (as defined in Exchange Act Rules 13a-14(c) and 15d-14(c)) are effective in timely alerting them to material information required to be disclosed in our periodic reports filed with the SEC.  It should be noted that the design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions, regardless of how remote.   In addition, we reviewed our internal controls, and there have been no significant changes in our internal controls or in other factors that could significantly affect those controls subsequent to the date of their last evaluation.

 

20

 

PART II – OTHER INFORMATION

 

ITEM 2.  CHANGES IN SECURITIES

In February 2003, options to purchase 135,000 shares of our common stock were issued to new employees with  exercise prices ranging from $.85 per share  to $.93 per share and expiring in 2013.  The options vest equally over a three year period beginning in February 2004.  The employees who were granted the options are sophisticated investors with meaningful access to all material information regarding the Company, its business and operations and its outstanding common stock.  Those employees acquired the options, and will acquire the underlying shares upon exercise, for investment purposes only and not with a view to the distribution thereof.  Thus, the grants of the options were exempt from the registration requirements of the Securities Act of 1933, as amended, under Section 4(2) thereof.

 

ITEM 5.  OTHER INFORMATION

On April 21, 2003, Joe C. Richardson, Jr., an outside director, elected to retire and submitted his resignation to the Board of Directors.  The Board of Directors unanimously accepted Mr. Richardson’s resignation on April 28, 2003.

 

ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K

 

(a)		EXHIBIT NO.		DESCRIPTION
		99.1		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
		99.2		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(b)		Form 8-K dated March 5, 2003 reported Item 5. the 2002 year-end results and 2003 guidance for the Company.

 

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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:  May 14, 2003	By:	/s/ Joseph L. Burnett
		Joseph L. Burnett
		Chief Financial Officer and
		Principal Accounting Officer

 

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CERTIFICATIONS

 

I, David A. Wilkins, certify that:

 

1.               I have reviewed this quarterly report on form 10-Q of Beta Oil & Gas, Inc.

 

2.               Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

 

3.               Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

 

4.               The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

 

a.               Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

 

b.              Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

 

c.               Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

5.               The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 

a.               All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weakness in internal controls; and

 

b.              Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

6.               The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

 

Date: May 14, 2003
	By:	/s/ David A. Wilkins
	David A. Wilkins
	President and Chief Executive Officer
	(Principal Executive Officer)

 

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CERTIFICATIONS

 

I, Joseph L. Burnett, certify that:

 

1.               I have reviewed this quarterly report on form 10-Q of Beta Oil & Gas, Inc.

 

7.               Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

 

8.               Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

 

9.               The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

 

a.               Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

 

b.              Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

 

c.               Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

 

10.         The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

 

a.               All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weakness in internal controls; and

 

b.              Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

 

11.         The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

 

 

Date: May 14, 2003
	By:	/s/ Joseph L. Burnett
	Joseph L. Burnett
	Chief Financial Officer
	(Principal Financial Officer)

 

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