WASHINGTON, D.C.  20549

 

 

FORM 10-Q

 

 

 

 

BETA OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

 

 

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, 2004, the Registrant had 12,429,307 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, 2004 (unaudited) and December 31, 2003
		Condensed Consolidated Statements of Operations for the three months ended March 31, 2004 and March 31, 2003 (unaudited)
		Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2004 and March 31, 2003 (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
		Overview
		Liquidity and Capital Resources
		Plan of Operation for 2004
		Comparison of Results of Operations for the three months ended March 31, 2004 and 2003
		Income Taxes
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk
ITEM 4.	Controls and Procedures
PART II. -	OTHER INFORMATION
ITEM 6.	Exhibits and Reports on Form 8-K
Signatures

 

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PART I

ITEM 1.  FINANCIAL STATEMENTS

BETA OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		MARCH 31, 2004			DECEMBER 31, 2003
		(Unaudited)
CURRENT ASSETS:
Cash		$	2,359,790		$	2,109,681
Accounts receivable
Oil and gas sales		2,118,990			1,898,746
Other		94,378			113,529
Income tax receivable		—			5,934
Prepaid expenses and other		120,004			266,728
Total current assets		4,693,162			4,394,618
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties		80,319,688			78,717,380
Unevaluated properties		1,216,179			1,294,212
Less – accumulated amortization of full cost pool		(40,762,797		)	(39,740,116		)
Net oil and gas properties		40,773,070			40,271,476
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system and equipment		1,502,692			1,496,404
Support equipment		197,379			197,379
Other		276,498			276,498
Less – accumulated depreciation		(861,908		)	(813,450		)
Net other operating property and equipment		1,114,661			1,156,831
OTHER ASSETS		190,803			292,318
TOTAL ASSETS		$	46,771,696		$	46,115,243
CURRENT LIABILITIES:
Note payable		$	21,957		$	67,570
Accounts payable, trade		1,578,599			1,578,989
Dividends payable		111,482			112,707
Asset retirement obligation – current portion		171,860			171,860
Income taxes payable		17,291			—
Other accrued liabilities		374,063			566,990
Total current liabilities		2,275,252			2,498,116
LONG-TERM DEBT, less current portion		13,284,652			13,284,652
ASSET RETIREMENT OBLIGATIONS		1,083,644			1,062,860
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,271 issued and outstanding at March 31, 2004 and December 31, 2003.  Liquidation preference at March 31, 2004 is $5,700,872.		604			604
Common stock, $.001 par value; 50,000,000 shares authorized; 12,446,072 shares issued; 12,429,307 and 12,440,057 shares outstanding at March 31, 2004 and December 31, 2003.		12,447			12,447
Additional paid-in capital		51,882,013			51,924,225
Treasury stock, at cost; 16,765 shares reacquired at March 31, 2004 and December 31, 2003.		(36,428		)	(36,428		)
Accumulated deficit		(21,730,488		)	(22,631,233		)
Total stockholders’ equity		30,128,148			29,269,615
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	46,771,696		$	46,115,243

 

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,
		2004			2003
REVENUES:
Oil and gas sales		$	3,878,531		$	2,893,347
Field services		173,863			207,888
Total revenue		4,052,394			3,101,235
COSTS AND EXPENSES:
Lease operating expense		928,336			797,521
Field services		45,301			51,837
General and administrative		860,966			813,811
Depletion, depreciation and amortization expense		1,071,139			1,335,068
Total costs and expenses		2,905,742			2,998,237
INCOME FROM OPERATIONS		1,146,652			102,998
OTHER INCOME (EXPENSE):
Interest expense		(112,627		)	(122,292		)
Interest income and other		1,425			873
Total other expense		(111,202		)	(121,419		)
INCOME (LOSS) BEFORE INCOME TAX		1,035,450			(18,421		)
INCOME TAX PROVISION		(23,225		)	—
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTNG PRINCIPLE		1,012,225			(18,421		)
CUMULATIVE EFFECT ON PRIOR YEARS FROM ADOPTION OF FASB STATEMENT NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATION (NOTE 3)		—			1,640
NET INCOME (LOSS)		1,012,225			(16,781		)
PREFERRED DIVIDENDS		(111,482		)	(110,256		)
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS		$	900,743		$	(127,037	)
BASIC NET INCOME (LOSS) PER COMMON SHARE		$	.07		$	(.01	)
DILUTED NET INCOME (LOSS) PER COMMON SHARE		$	.07		$	(.01	)
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		$	1,012,225		$	(16,781	)
OTHER COMPREHENSIVE INCOME:
Reclassification of realized loss on qualifying cash flow hedges		—			1,031,009
Unrealized loss on qualifying cash flow hedges		—			(540,282		)
TOTAL COMPREHENSIVE INCOME		$	1,012,225		$	473,946

 

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 CASH FLOWS

(unaudited)

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) before cumulative effect of change in accounting principle		$	1,012,225		$	(18,421	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization		1,071,139			1,335,068
Compensation expense from stock options		23,752			2,728
Change in operating assets and liabilities:
Accounts receivable		(201,093		)	(965,539		)
Income taxes		23,225			28,906
Prepaid expenses		146,724			71,581
Accounts payable, trade		(390		)	(130,457		)
Other accrued expenses		(192,926		)	36,014
Accretion of asset retirement obligations		23,026			13,703
Asset retirement obligations incurred		(2,242		)	(5,314		)
Net cash provided by operating activities		1,903,440			368,269
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property expenditures		(1,707,057		)	(286,499		)
Proceeds received from sale of oil and gas properties		182,782			—
Change in other assets		101,515			65,369
Gas gathering and other equipment expenditures		(6,287		)	(31,284		)
Net cash used in investing activities		(1,429,047		)	(252,414		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of notes payable		(45,613		)	(56,580		)
Deferred offering costs relative to pending Petrohawk transaction		(65,964		)	—
Dividends paid		(112,707		)	(112,708		)
Acquisition of treasury stock		—			(7,111		)
Net cash used in financing activities		(224,284		)	(176,399		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		250,109			(60,544		)
CASH AND CASH EQUIVALENTS:
Beginning of period		2,109,681			927,313
End of period		$	2,359,790		$	866,769
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest		$	112,627		$	123,482

 

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

 

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CONDENSED FINANCIAL STATEMENTS

 

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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, 2004 and the results of its operations and cash flows for the three months ended March 31, 2004 and 2003.  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, 2003 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/A for the fiscal year ended December 31, 2003 that was filed April 20, 2004.

 

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 units 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, if the properties have similar characteristics.  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 at 10%, net of tax considerations. Any impairments to unevaluated properties are recorded as transfers to the full cost pool.

 

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.

 

3.                                       ASSET RETIREMENT OBLIGATIONS:

 

The Company adopted SFAS No. 143 effective January 1, 2003.  SFAS No. 143 requires that the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.  Upon adoption, the Company recorded an asset retirement obligation of $913,560 to reflect the Company’s legal obligations related to future plugging and abandonment of its wells.  The Company estimated the expected cash flow associated with the obligation and discounted the amount using a credit-adjusted, risk-free interest rate of 8%.  The transition adjustment resulting from the adoption of SFAS No. 143, and reported

 

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as a cumulative effect of a change in accounting principle, was an increase to income of $1,640 in 2003.  There was no comparable adjustment in 2004.

 

The Company recorded the following activity related to the liability for the three months ended March 31, 2004 and 2003:

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2004			2003
Beginning balance - liability for asset retirement obligations		$	1,234,720		$	—
Initial liability for asset retirement obligations as of January 1, 2003		—			913,560
Obligations fulfilled		(2,242		)	(5,314		)
Accretion expense		23,026			13,703
Ending balance - liability for asset retirement obligations		$	1,255,504		$	921,949

 

At March 31, 2004, $171,860 of the liability for asset retirement obligations balance is classified as current and presented as a separate line item.

 

4.                                       STOCKHOLDERS’ EQUITY:

 

Stock Option Based Compensation

 

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS No. 123”) and related interpretations in accounting for its employee and director stock options and applies the fair value based method of accounting to such options.  Under SFAS No. 123, the fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model.  Under Statement of Financial Accounting Standards No. 148 Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS No. 123, certain transitional alternatives were 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 used the prospective method which applies 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.  Previous to the adoption, the Company elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB 25) and related interpretations in accounting for its employee stock options.  However, as required by SFAS No. 123, the Company disclosed on a pro forma basis the impact of the fair value accounting for employee stock options.  Transactions in equity instruments with non-employees for goods or services have been accounted for using the fair value method as prescribed by SFAS No. 123.

 

Since the Company adopted the fair value recognition provisions of SFAS No. 123 prospectively for all employee awards granted, modified or settled after January 1, 2003, the cost related to stock-based compensation included in the determination of income for the three month periods ended March 31, 2004 and 2003 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 SFAS No. 123.  Awards vest over periods ranging from one to three years.  The following table illustrates the effect on net income (loss) and earnings (loss) per share as if the fair value based method had been applied to all outstanding and unvested awards in each period.

 

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		FOR THE THREE MONTHS ENDED MARCH 31,
		2004			2003
Net income (loss) applicable to common shareholders as reported		$	900,743		$	(127,037	)
Add:  Stock-based compensation expense included in reported net income (loss)		23,752			2,728
Deduct:  Total stock-based compensation expense determined under fair value method for all awards		(57,352		)	(45,088		)
Pro forma net income (loss) applicable to common shareholders		$	867,143		$	(169,397	)
Income (loss) per share;
Basic – as reported		$	.07		$	(.01	)
Basic – pro forma		$	.07		$	(.01	)
Diluted – as reported		$	.07		$	(.01	)
Diluted – pro forma		$	.07		$	(.01	)

 

The fair value of each grant is estimated on the date of grant using the Black-Scholes option-pricing model.  The weighted average assumptions used for options granted in 2003 include expected volatility of approximately 61.3%, a risk-free interest rate of 3.15% and expected lives of 5.2 years.

 

Options

 

No options were issued during the three months ended March 31, 2004.

 

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.

 

The Company did not purchase any shares during the three months ended March 31, 2004.  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, 2004, the Company held 16,765 treasury shares with a market value of $48,619, or $2.90 per share.

 

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5.                                       NET INCOME (LOSS) PER COMMON SHARE:

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2004			2003
Basic:
Net income (loss)		$	1,012,225		$	(16,781	)
Less:  Preferred dividends		(111,482		)	(110,256		)
Net income (loss) applicable to common shareholders		$	900,743		$	(127,037	)
Weighted average number of common shares		12,429,307			12,438,310
Basic earnings (loss) per share		$	.07		$	(.01	)
Diluted:
Net income (loss) applicable to common shareholders		$	900,743		$	(127,037	)
Add:  Preferred dividends		—			—
Net income (loss) for diluted earnings (loss) per share		$	900,743		$	(127,037	)
Weighted average number of common shares		12,429,307			12,438,310
Common stock equivalent shares representing shares issuable upon exercise of stock options		711,598			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 income (loss) per share		13,140,905			12,438,310
Diluted earnings (loss) per share		$	.07		$	(.01	)

 

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

 

		MARCH 31,
Common Stock Equivalents:		2004		2003
Incentive stock options		253,000		466,500
Non-qualified options		—		635,000
Warrants		1,839,000		1,839,000
“As-if” conversion of preferred stock		604,271		604,271
		2,696,271		3,544,771

 

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6.                                       LONG-TERM DEBT:

 

During 2003, the Company’s revolving credit agreement with a commercial bank was re-determined and its maturity extended to April 1, 2005.  At March 31, 2004, the $25,000,000 credit facility had a borrowing base of $13,708,000, which is subject to an automatic monthly reduction of $88,000 that commenced July 31, 2003 and is collateralized by the Company’s oil and gas properties and gas gathering system and related assets.  At March 31, 2004, the outstanding amount against the borrowing base was $13,284,652 and the effective interest rate, which is a LIBOR base rate plus 2.2%, was 3.3%.  The Company pays a fee equal to .25% (1/4 of a percentage point) on the unused portion of the borrowing base, which was approximately $223,000 at March 31, 2004, due quarterly in arrears.  The next re-determination for the borrowing base will occur in the second quarter of 2004.

 

At March 31, 2004, the Company had various outstanding letters of credit of $201,000, which reduces the amount available under the borrowing base.  The Company pays an annual renewal of 2.25% of the face amount of the letter of credit.

 

7.             DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

 

Natural Gas - During the three months ended March 31, 2004, the Company had no outstanding commodity price hedging contracts.  From time to time, the Company may hedge a portion of its natural gas production and use collars, swaps or a combination of those derivatives when hedging.  The collar arrangements are costless and no net premium is received in cash.

 

For the three months ended March 31, 2004 no contracts were settled and no natural gas production was hedged during the period.

 

For the contracts settled during the three months ended March 31, 2003, the Company had realized losses of $849,225 (no tax effect).  The impact of the natural gas hedges reduced the Company’s average natural gas price received for the three months ended March 31, 2003 by $1.86 per Mcf.  Based on the actual average daily 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.  Hedge ineffectiveness was not material during this period.

 

Crude Oil - During the three months ended March 31, 2004, the Company had no outstanding commodity price hedging contracts.  From time to time, the Company may hedge a portion of its crude oil production and use collars, swaps or a combination of those derivatives when hedging.  The collar arrangements are costless and no net premium is received in cash.

 

For the three months ended March 31, 2004 no contracts were settled and no crude oil production was hedged during the period.

 

For the contracts settled during the three months ended March 31, 2003, the Company had realized losses of $181,784 (no tax effect).  The impact of the crude oil hedges reduced the Company’s average crude price received for the three months ended March 31, 2003 by $6.21 per Bbl.  Based on the actual average daily 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.  Hedge ineffectiveness was not material during this period.

 

8.             PENDING TRANSACTION:

 

On December 12, 2003, the Company entered into a securities purchase agreement with Petrohawk Energy, LLC (“Petrohawk”), a privately-held independent exploration and production company headquartered in Houston, Texas, pursuant to which Petrohawk has agreed to a cash investment of $60,000,000 in the

 

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Company’s common stock, warrants and a convertible note.  Pending approval by the Company’s shareholders, the Company will receive $25,000,000 for the issuance of 15,151,515 shares of its common stock and 10,000,000 five-year common stock purchase warrants exercisable at a price of $1.65 per share.  Additionally, the Company will issue a $35,000,000 convertible note that will be an unsecured five-year obligation and after two years will be convertible by the holder into the Company’s common stock at a conversion price of $2.00 per share.  Interest only will be payable under the note in quarterly installments at the rate of 8% per annum.  The full amount of the principal and accrued and unpaid interest will be payable on the fifth anniversary of the date of the note.  Future use of these proceeds would include acquisitions of oil and gas properties, future development and exploitation of existing and acquired oil and gas properties and exploration activity.  A portion of these proceeds is expected to be used to repay all of the Company’s existing long-term bank debt.

 

On April 23, 2004, the Company mailed its definitive proxy statement to its shareholders.  A special shareholders’ meeting will be held on May 25, 2004 to vote on, among other items, the Petrohawk transaction.

 

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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, 2004 and December 31, 2003 and the results of operations for the three-month periods ended March 31, 2004 and 2003.

 

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 2004

•                  The proposed Petrohawk transaction described further below under Petrohawk Transaction.

 

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/A 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.

 

Petrohawk Transaction

 

On December 12, 2003, we entered into a securities purchase agreement (which we generally refer to as the Petrohawk purchase agreement) with Petrohawk Energy, LLC (“Petrohawk”) pursuant to which we have agreed to issue to Petrohawk for an aggregate of $60,000,000 in cash:

 

•      15,151,515 shares of our common stock;

 

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•      five year warrants to purchase up to an additional 10,000,000 shares of our common stock at an exercise price of $1.65 per share; and

 

•      a convertible promissory note in the face amount of $35,000,000 which will be convertible after two years into shares of our common stock at a conversion price of $2.00 per share.

 

Because issuance of the shares of common stock to Petrohawk in connection with this transaction will result in a change of control of Beta, we are required by the rules of The Nasdaq Stock Market to obtain stockholder approval of the issuance of the shares.  A special meeting of our stockholders is scheduled to be held on May 25, 2004 at 10:00 a.m., local time, in the 19^th Floor Conference Room A, Warren Place Two, 6120 S. Yale Avenue, Tulsa, Oklahoma.

 

The transactions contemplated by the purchase agreement are required to be consummated at a closing that we expect to occur immediately following the approval of the proposal by our stockholders.  Holders of approximately 28% of our outstanding common stock have entered into an agreement with Petrohawk in which they committed to vote their shares in favor of the transaction.

 

Assuming that the transaction is approved by our stockholders and is consummated, the proceeds from the sale of the securities will be added to our working capital and be available for the acquisition, development and exploration of oil and gas properties.  A portion of these proceeds is expected to be used to repay all of our existing long-term bank debt.  Under the terms of the Petrohawk purchase agreement, all of our directors except Robert C. Stone, Jr. will resign and six persons designated by Petrohawk will be appointed as new directors.  New management will also be appointed and it is anticipated that our headquarters will be moved to Houston, Texas.

 

A more complete discussion of the Petrohawk transaction is contained in the section captioned “Proposal No. 1: The Petrohawk Transaction” in our definitive proxy statement which was mailed to our shareholders on April 23, 2004 and filed with the SEC on the same date.

 

Much of the discussion in this section about 2004 and our future business, operations and activities is subject to the effects of the Petrohawk transaction if and when it is consummated.

 

Overview

 

In the first quarter of 2004, a sustained improvement in our financial condition was a result of higher cash flows from operations.  A continuing favorable commodity price environment and increasing production rates were the primary factors for the improving cash flow.  With the success of our exploration, exploitation and development activity in the last half of 2003 and first quarter of 2004, our current production rates have increased.  Our net daily average production rate for the three months ended March 31, 2004 was approximately 7.5 MMcfe compared to 7.0 MMcfe for the same period ended in 2003, a 7% increase.  We continue to be optimistic about the long-term outlook for natural gas and crude oil but realize that the overall environment for commodity pricing is very volatile and can be materially affected, favorably or unfavorably, by such factors as global uncertainty, imports/exports, weather trends, power generation and industrial demands.

 

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.

 

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

 

		FOR THE THREE MONTHS ENDED MARCH 31,
		2004			2003
Beginning cash balance		$	2,109,681		$	927,313
Sources of cash:
Cash provided by operations		1,903,440			368,269
Cash provided by sales of oil & gas properties		182,782			—
Total sources of cash including cash on hand		4,195,903			1,295,582
Uses of cash:
Oil and gas expenditures, net of prepaid drilling advances		(1,605,542		)	(221,130		)
Other equipment		(6,287		)	(31,284		)
Cash used by financing activities		(224,284		)	(176,399		)
Total uses of cash		(1,836,113		)	(428,813		)
Ending cash balance		$	2,359,790		$	866,769

 

Working capital and liquidity:

 

Our working capital was a surplus of $2,417,911 at March 31, 2004, compared to a surplus of $1,896,502 at December 31, 2003 and a surplus of $1,371,662 at March 31, 2003.  Our working capital and liquidity have shown continual improvement as a result of higher cash flows from operations.  Additionally, at March 31, 2004 and December 31, 2003, we had no futures derivative liability associated with our future production volume compared to a futures derivative liability at March 31, 2003, of $211,690, which represented the potential unrealized reduction in our future oil and gas revenue based on the current outstanding derivative contracts at that time.

 

Our principal source of short-term liquidity is from internally-generated cash flow.  Should natural gas and crude oil prices decrease materially, our current operating cash flow would decrease and our liquidity and working capital position would be negatively impacted and could adversely impact our growth capability.

 

Current borrowing base:

 

Our borrowing base capacity under the current credit facility is presently 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 if pricing materially declines, our borrowing base could be reduced below the amount currently borrowed and outstanding under the facility.  If this event were to occur 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 and/or proved undeveloped properties 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 was re-determined and extended during the quarter ended June 30, 2003, has a maturity date of April 1, 2005 and at March 31, 2004 had a borrowing capacity of $13,708,000 subject to an automatic monthly reduction of $88,000, which commenced on July 31, 2003.  At March 31, 2004, a balance of $13,284,652 was outstanding against the borrowing base and the effective interest rate, which is a LIBOR base rate plus 2.2%, was 3.3%.

 

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 exploitation, developmental and exploration activities in future periods, gas and oil price conditions and other related economic factors.  The following tables show our contractual obligations and commitments, in which no material changes have occurred since December 31, 2003.

 

		Payments Due by Period
Contractual Obligations		Total			Less than 1 year			1-3 years			4-5 years			After 5 years
Long –Term Debt (1)		$	13,722,114		$	437,462		$	13,284,652		$	—		$	—
Operating Leases (2)		48,589			32,533			16,056
Other (3)		18,750			18,750			—			—			—
Total cash obligations		$	13,789,453		$	488,745		$	13,300,708		$	—		$	—

 

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(1)                         $13,722,114 represents principal and interest related to our current credit agreement with a commercial bank.  For further information please refer to PART 1. FINANCIAL STATEMENTS, ITEM 1. Financial Statements, Note 6, LONG-TERM DEBT.

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

(3)                         Represents amounts due under a financial advisory 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		$	201,000		$	201,000		—		—		—

 

The letters of credit were issued in connection with our operations for such items as production tax, drilling requirements with various state agencies and utility deposits.

 

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

 

Plan of Operation for 2004

 

For the three months ended March 31, 2004, we had capital expenditures, net of drilling prepayments, of approximately $1.6 million.  The expenditures related to the following projects:

 

•                  $.4 million expended for drilling and recompletion activity at our West Edmond Hunton Lime Unit (“WEHLU”), Oklahoma County, OK.    During the quarter we participated in the drilling of one gross (.35 net) well which was successfully completed subsequent to March 31, 2004.  Additionally, three wells were recompleted and stimulated during this period as part of our ongoing exploitation and development program for WEHLU.  For the quarter, our daily net production from WEHLU was approximately 2.5 MMcfe as compared to 2.4 MMcfe for the same quarter in 2003.  Subsequent to March 31, 2004, we participated with a 36% working interest in the drilling of an additional well that at the date of this report is in the drilling phase.

 

•                  $.4 million expended on drilling and completion activity in South Central, Kansas.  The remaining two wells of the 13 well drilling program were successfully completed during the quarter.  Nine of the 13 wells drilled were successful of which two wells are awaiting pipeline connection.  Our current estimated net daily production from the seven producing wells is 570 Mcfe.

 

•                  $.7 million expended for drilling and completion in our Lapeyrousse, Louisiana area.  We participated with an 8% working interest in the drilling and successful completion of one well during the quarter.  We also have an approximate 5% working interest in a well that was successfully completed during the quarter that was drilling at year end.

 

•                  $.1 million expended for additional leasing activity in our Broussard, Louisiana area.  The Montesano #1, West unit location, commenced drilling late in the first quarter and is expected to reach total measured depth of approximately 16,500’ late in the second quarter.  We are participating with a 9.6% working interest in this well increasing to a 13.8% working interest after well payout.  During the quarter, we sold approximately 22% of the 83.6% working interest we owned, or 18.5%, in the West unit of the Broussard prospect for approximately $182,800 and a .9% reversionary interest.  Subsequent to March 31, 2004, an additional 67% of the working interest we owned, or 55.5%, was sold for approximately $549,700 and a 3.8% reversionary interest in the West unit.  If the Montesano #1 is successful, we could receive an additional $1.1 million in the form of production payments from the well’s future net cash flows.

 

Assuming the Petrohawk transaction is not consummated, for the year 2004 we expect to fund our capital requirements from net cash flow from operations (after general and administrative expense and interest expense).

 

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We project our 2004 capital expenditure to be approximately $5.0 million.  The areas and amounts of concentration for the capital program will be:

 

•                  West Edmond Hunton Lime Unit, Oklahoma - $2.9 million

•                  Lapeyrouse Field, Terrebonne Parish, Louisiana - $.8 million

•                  West Broussard Prospect, Lafayette Parish, Louisiana - $.8 million

•                  McIntosh County, Oklahoma - $.2 million

•                  Brookshire Dome Area, Waller County, Texas - $.2 million

•                  Other - $.1 million

 

We are projecting our cash flows from operations to be approximately $7.5 million based on an average NYMEX natural gas price of $4.02 per Mcf, as adjusted for basis differentials, and an average NYMEX spot crude oil price of $24.95 per barrel, as adjusted for quality and an average net daily production of 9.2 MMcfe.  Any proceeds from the sale or reduction of our working interests in certain 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 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 a price of $7.50 per warrant.  However, it is our intent to call all of these warrants at such time, if and when, the market price of our common stock exceeds the exercise price of the warrants and the cash is needed to fund capital requirements.  If warrants are exercised, we will receive proceeds equal to the exercise price times the number of shares which are issued as a result of the exercise of any 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 2004.

 

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 higher than projected 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 2004.

 

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;

 

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 lesser interest; or

 

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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 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.

 

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.

 

Critical 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

•      Stock option compensation

 

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 our condensed 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.

 

Oil and gas properties - We account for our oil and gas producing activities using the full cost method of accounting.  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 units 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.  During the three month period ended March 31, 2004, unevaluated leasehold costs and related brokerage fees of $114,161 were transferred to U.S. evaluated costs, or the full cost pool.  For the remaining costs, which includes seismic and geological and geophysical primarily related to Jackson County Texas, historically we have estimated reserve potential for the unevaluated properties using comparable

 

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producing areas or wells and risk 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.

 

For 2003, it was the Company’s desire to have an industry partner or partners with geotechnical expertise to study and further evaluate the seismic data in order to fully evaluate the potential of the areas.  Even though discussions with third parties were conducted, no arrangements were finalized in 2003.  Since no significant internal evaluation activity occurred in 2003, the Company believed it inappropriate to apply the same methodology used in prior years for its assessment of the Jackson County costs, which represents an average 20% working interest in 286 square miles of proprietary seismic and related interpretational data.  At December 31, 2003, the Company believed it more appropriate, due to the previously discussed circumstances and events with respect to Jackson County, to assess impairment based on the estimated value of the seismic data if sold or exchanged for other seismic data.  The assessment resulted in an impairment of $1,627,116 and the resulting impairment was transferred to U.S. evaluated costs and will be subject to amortization.  There was no comparable adjustment for the three months ended March 31, 2004.

 

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.  Typically, our derivative contract will consist 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 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 - - Subsequent to December 31, 2002, we adopted Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (“SFAS 123”) and related interpretations in accounting for our employee and director stock options.  Under SFAS No. 123, the fair value of each option granted is estimated on the date of grant using the Black-Scholes option-pricing model.  As allowed by Statement of Financial Accounting Standards No. 148 Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to SFAS 123, certain transitional alternatives were 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, 2002.  We adopted the prospective method which applies 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, or in this case January 1, 2003.

 

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Comparison of Results of Operations

 

Quarter ended March 31, 2004 and Compared to Quarter ended March 31, 2003

 

We had net income of $1,012,225 for the three months ended March 31, 2004 compared to a net loss of ($16,781) for the same period ended 2003.  A significantly higher natural gas and crude oil price environment, higher natural gas and crude oil sales volumes and lower depletion expense were the primary reasons for the increase in net income.  The increase was partially offset by higher lease operating expense and slightly higher general and administrative expenses during the first three months of this year when compared to same period for last year.

 

The following table summarizes key items of comparison and their related increase (decrease) for the periods indicated.  Dollars, except for per unit data, and production data are in thousands.

 

In Thousands		Three Months Ended March 31,						$ – Increase (Decrease)			% - Increase (Decrease)
		2004			2003
Net income (loss)		$	1,012.2		$	(16.8	)	$	1,029.0		6125	%
Oil and gas sales		3,878.5			2,893.3			985.2			34	%
Field service income		173.9			207.9			(34.0		)	(16	)%
Lease operating expense		706.6			580.5			126.1			22	%
Production tax expense		221.7			217.0			4.7			2	%
Field service expense		45.3			51.8			(6.5		)	(13	)%
G&A expense		861.0			813.8			47.2			6	%
Depletion		1,022.7			1,280.8			(258.1		)	(20	)%
Depreciation – Field service and other		45.5			54.2			(8.7		)	(16	)%
Interest expense		112.6			122.3			(9.7		)	(8	)%
Income tax provision		23.2			—			23.2
Production:
Natural Gas – Mcf		480.7			454.5			26.2			6	%
Crude Oil – Bbl		33.8			29.2			4.6			15	%
Natural Gas Equivalent – Mcfe		683.2			630.0			53.2			8	%
$  per unit:
Ave. gas price per Mcf		$	5.74		$	4.71		$	1.03		22	%
Ave. oil price per Bbl		33.16			25.72			7.44			29	%
Ave. lease operating expense per Mcfe		1.03			0.90			0.13			15	%
Ave. production tax expense per Mcfe		0.32			0.34			(0.02		)	(6	)%
Ave. G&A per Mcfe		1.26			1.29			(0.03		)	(2	)%
Ave. depletion per Mcfe		1.50			2.03			(0.53		)	(26	)%

 

Oil and gas sales:

 

For the three months ended March 31, 2004, oil and gas sales increased $985,184, or 34%, from the same period in 2002, to $3,878,531.  The increase for the three months was a result of higher natural gas and crude oil prices received and higher sales volumes during the quarter ended March 31, 2004.  Lower national storage levels, supply uncertainty due to global events and a weaker U.S. dollar, which impacts the OPEC basket price, favorably impacted crude oil prices.  In turn, natural gas prices have remained stronger due to the higher crude oil prices and seasonal demand during the quarter.  The prices received for our natural gas and crude oil during the quarter ended March 31, 2003 were also unfavorably impacted by our commodity hedges, as discussed further below under Hedging.

 

The higher commodity prices resulted in an increase in oil and gas revenues of $746,115, with higher natural gas prices comprising 66% of the increase.  Higher natural gas and crude oil sales volumes resulted in additional oil and gas revenues of $239,069, with higher natural gas sales volumes comprising 51% of the increase.  The increase in production was a result of our drilling activity in the Broussard, Louisiana and Brookshire Dome, Texas properties and the drilling and recompletion activity during the last half of 2003 and this quarter on the WEHLU, Oklahoma properties.  Our incremental increase in production from these areas was partially offset by the natural decline in the production rates from our offshore Louisiana and South Texas properties.

 

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Hedging:

 

Generally, we sell our natural gas and crude oil to various purchasers on an indexed-based or spot price.  The indices for natural gas are generally affected by the NYMEX – Henry Hub spot prices while the posted prices for crude oil are generally affected by the NYMEX-Crude Oil West Texas Intermediate prices.  From time to time, we use financial derivative instruments on a limited basis to lessen the impact of price volatility.

 

For the three months ended March 31, 2004, we had no hedges on our production.  For the three months ended March 31, 2003, hedges covered approximately 57% of our production on an equivalent MMbtu basis.  Oil and gas revenues for the three months ended March 31, 2003 were reduced by approximately $1,031,000 due to our oil and gas hedges.  For the three months 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 our crude oil was reduced by approximately $6.21 per Bbl from our crude oil hedges.  For further discussion please refer to PART 1. FINANCIAL STATEMENTS, ITEM 1. Financial Statements, Note 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.

 

Based on our natural gas production for the three months ended March 31, 2004, a decline in our average natural gas price realized of $1.00 per Mcf would have resulted in an approximate $.346 million reduction in net income before income taxes for the three month period.

 

Lease operating and production tax expenses:

 

Lease operating expense, excluding production taxes, increased $126,059, or 22%, to $706,608 for the three months ended March 31, 2004 compared to the same period for 2003.  The increase was primarily due to higher operating expense associated with our offshore Louisiana properties, the Peace Creek and Zenith Field, Kansas properties and recently drilled wells in South Central Kansas and WEHLU, Oklahoma.

 

Production tax expense increased $4,756, or 2%, for the three months ended March 31, 2004 as compared to the same period ended in 2003, due to higher natural gas and crude oil revenues.  Production taxes are generally assessed as a percentage of gross oil and/or natural gas sales amounts or volumes.

 

General and administrative expense:

 

General and administrative expense for the three months ended March 31, 2004 increased $47,155, or 6%, to $860,966 compared to $813,811 for the same period in 2003.  The increase was due primarily to higher audit fees and other corporate expenses during the quarter.

 

During the three months ended March 31, 2004, we incurred approximately $66,000 of costs associated with the pending Petrohawk transaction, which were recorded as deferred costs and reflected as a reduction to paid-in-capital.  At March 31, 2004, we had a total of approximately $311,000 of deferred costs associated with the pending Petrohawk transaction.  Should we not consummate the Petrohawk transaction, these costs would be reflected in our general and administrative expense at that time.

 

Depletion, depreciation and amortization expense:

 

Depletion, depreciation and amortization expense decreased $263,929, or 20%, from the same period in 2003 to $1,071,139 for the three months ended March 31, 2004.  Depletion associated with evaluated oil and gas properties comprised 98% of the decrease.  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.  The decrease in oil and gas depletion was due to a lower depletion rate for the first quarter of 2004 which resulted from a significant increase in our December 31, 2003 proved reserves.  The depletion rates per Mcf for the three months ended March 31, 2004 and 2003 were $1.50 per Mcf and $2.03 per Mcf, respectively.

 

Depreciation expense for other assets includes depreciation 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.  Depreciation expense for the three month periods ended March 31, 2004 and 2003 was $48,458 and $54,241, respectively.

 

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Interest expense:

 

Interest expense decreased for three months ended March 31, 2004 as compared to the same period 2003 by approximately $10,000 due to a lower outstanding debt balance and slightly lower interest rates in 2004.

 

Income Taxes

 

As of March 31, 2004, we had available, to reduce future taxable income, a U.S. federal regular net operating loss (“NOL”) carryforward of approximately $23.5 million and a U.S. federal alternative minimum tax NOL carryforward of approximately $20.2 million, which expire in the years 2018 through 2023.  We also had various state NOL carryforwards at March 31, 2004, with varying lengths of allowable carryforward periods ranging from five to 20 years and can be used to offset future state taxable income. Based on past results and current forecasts, we have established a valuation allowance to reduce net deferred taxes to zero.  We had $23,225 of alternative minimum tax expense for the three months ended March 31, 2004.  There was no change in deferred taxes during the periods presented and we had no net deferred taxes at March 31, 2004.

 

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.  However, if we consummate the proposed Petrohawk transaction, the amount of the NOL carryforwards that we will be able to use in any one year will be significantly restricted.  This is because Petrohawk will own approximately 55% of our outstanding common stock, if the transaction is consummated, resulting in a change of control.

 

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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 instruments.    At March 31, 2004, we had no outstanding derivative financial instruments due to a projected strong market for both natural gas and crude oil.  For more information please refer to PART 1. FINANCIAL STATEMENTS, ITEM 1. Financial Statements, Note 7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.

 

We are also exposed to market risk related to adverse changes in interest rates.  Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based on borrowing from our commercial bank.  At March 31, 2004, all of our outstanding debt was at variable rates.  This 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.  Based on a 10% increase or decrease in interest rates, our interest expense and net income would have increased or decreased by approximately $11,000 for the three months ended March 31, 2004 and approximately $12,000 for the three months ended March 31, 2003.

 

Item 4.  Controls and Procedures

 

Based on their evaluation, our Chief Executive Officer and Principal Financial Officer have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report on Form 10-Q are effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

 

During the period covered by this report on Form 10-Q, there have been no changes in the Company’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

 

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PART II – OTHER INFORMATION

 

Item 6.  Exhibits and Reports on Form 8-K

 

(a)          The following documents are included as exhibits to this Form 10-Q

 

31.1                     Certification of Periodic Report by the Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002

 

31.2                     Certification of Periodic Report by the Chief Financial Officer under Section 302 of Sarbanes-Oxley Act of 2002

 

32.1                     Certification of Periodic Report by the Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002

 

(b)         Reports on Form 8-K

 

The Company furnished two current reports on Form 8-K addressing events described under Items 9 and 12 of that form, it did not file any such reports during the quarter ended March 31, 2004.

 

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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 11, 2004	By:	/s/ Joseph L. Burnett
		Joseph L. Burnett
		Chief Financial Officer and
		Principal Accounting Officer

 

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