UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

 

 

WASHINGTON, D.C.  20549

 

 

FORM 10-Q

 

 

Commission File Number:  000-25717

 

 

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 12-b-2 of the Exchange Act).

 

Yes o  No ý

 

As of October 1, 2003, 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 September 30, 2003 (unaudited) and December 31, 2002
	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2003 and September 30, 2002 (unaudited)
	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2003 and September 30, 2002 (unaudited)
	Supplemental Disclosure of Noncash Investing and Financing Activities for the nine months ended September 30, 2003 and September 30, 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 September 30, 2003 and 2002
	Comparison of Results of Operations for the nine months ended September 30, 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
ITEM 6.	Exhibits and Reports on Form 8-K
Signatures

 

2

 

PART I

ITEM 1.  FINANCIAL STATEMENTS

BETA OIL & GAS, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		SEPTEMBER 30, 2003			DECEMBER 31, 2002
		(Unaudited)
CURRENT ASSETS:
Cash		$	1,867,497		$	927,313
Accounts receivable
Oil and gas sales		1,691,948			1,676,935
Other		212,373			149,243
Income tax prepaid		15,062			52,115
Prepaid expenses		278,853			187,818
Inventory		3,023			—
Total current assets		4,068,756			2,993,424
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties		73,734,174			70,907,441
Unevaluated properties		3,904,157			4,582,605
Less – accumulated amortization of full cost pool		(38,589,675		)	(35,133,445		)
Net oil and gas properties		39,048,656			40,356,601
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system and equipment		1,492,635			1,507,177
Support equipment		221,413			221,413
Other		251,866			215,302
Less – accumulated depreciation		(779,558		)	(616,865		)
Net other operating property and equipment		1,186,356			1,327,027
OTHER ASSETS		283,372			76,208
TOTAL ASSETS		$	44,587,140		$	44,753,260
CURRENT LIABILITIES:
Note payable		$	157,236		$	70,831
Accounts payable, trade		643,915			1,909,226
Dividends payable		112,706			112,707
Futures transaction hedge liability		—			702,417
Other accrued liabilities		307,061			275,290
Total current liabilities		1,220,918			3,070,471
LONG-TERM DEBT, less current portion (NOTE 6)		13,284,652			13,634,652
ASSET RETIREMENT OBLIGATION (NOTE 3)		878,079			—
COMMITMENTS AND CONTINGENCIES (NOTE 7)
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,272 issued and outstanding at September 30, 2003 and December 31, 2002.  Liquidation preference at September 30, 2003 is $5,702,097		604			604
Common stock, $.001 par value; 50,000,000 shares authorized; 12,446,072 shares issued at September 30, 2003 and December 31, 2002, 12,429,307 and 12,440,057 shares outstanding at September 30, 2003 and December 31, 2002, respectively		12,447			12,447
Additional paid-in capital		52,128,871			51,917,235
Treasury stock, at cost; 16,765 shares and 6,015 shares reacquired at September 30, 2003 and December 31, 2002, respectively		(36,408		)	(28,153		)
Accumulated other comprehensive loss		—			(702,417		)
Accumulated deficit		(22,902,023		)	(23,151,579		)
Total stockholders’ equity		29,203,491			28,048,137
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	44,587,140		$	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 SEPTEMBER 30,						FOR THE NINE MONTHS ENDED SEPTEMBER 30,
		2003			2002			2003			2002
REVENUES:
Oil and gas sales		$	3,145,698		$	2,238,435		$	8,920,744		$	6,932,874
Field services		130,766			84,715			499,650			281,146
Total revenue		3,276,464			2,323,150			9,420,394			7,214,020
COSTS AND EXPENSES:
Lease operating expense		736,853			864,327			2,243,129			2,530,025
Field services		50,621			50,458			143,889			141,673
General and administrative		742,207			453,617			2,233,621			1,386,575
Depreciation and amortization expense		1,197,554			1,190,460			3,812,592			3,495,126
Total costs and expenses		2,727,235			2,558,862			8,433,231			7,553,399
INCOME (LOSS) FROM OPERATIONS		549,229			(235,712		)	987,163			(339,379		)
OTHER INCOME (EXPENSE):
Interest expense		(130,786		)	(143,649		)	(402,527		)	(426,878		)
Interest income and other		1,352			1,795			3,708			22,072
Loss from sale of asset		(5,983		)	—			(5,983		)	—
Total other income (expense)		(135,417		)	(141,854		)	(404,802		)	(404,806		)
INCOME (LOSS) BEFORE INCOME TAX		413,812			(377,566		)	582,361			(744,185		)
INCOME TAX (PROVISION) BENEFIT		—			—			—			—
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTNG PRINCIPLE		413,812			(377,566		)	582,361			(744,185		)
CUMULATIVE EFFECT ON PRIOR YEARS FROM ADOPTION OF FASB STATEMENT NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATION (NOTE 3)		—			—			1,640			—
NET INCOME (LOSS)		413,812			(377,566		)	584,001			(744,185		)
PREFERRED DIVIDENDS		(112,707		)	(112,707		)	(334,445		)	(334,445		)
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDERS		$	301,105		$	(490,273	)	$	249,556		$	(1,078,630	)
BASIC NET INCOME (LOSS) PER COMMON SHARE		$	.02		$	(.04	)	$	.02		$	(.09	)
DILUTED NET INCOME (LOSS) PER COMMON SHARE		$	.02		$	(.04	)	$	.02		$	(.09	)
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		$	413,812		$	(377,566	)	$	584,001		$	(744,185	)
OTHER COMPREHENSIVE INCOME:
Reclassification of realized loss (gain) on qualifying cash Flow hedges		100,789			237,726			1,336,844			290,515
Unrealized gain (loss) on qualifying cash flow hedges		(5,172		)	(283,547		)	(634,427		)	(1,371,825		)
TOTAL COMPREHENSIVE INCOME (LOSS)		$	509,429		$	(423,387	)	$	1,286,418		$	(1,825,495	)

 

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 NINE MONTHS ENDED SEPTEMBER 30,
		2003			2002
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) before cumulative effect of change in accounting principle		$	582,361		$	(744,185	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		3,812,592			3,495,126
Compensation expense from stock options		211,636			—
Loss on sale of asset		5,983			—
Change in operating assets and liabilities:
Accounts receivable		(78,143		)	404,928
Income taxes prepaid or receivable		37,053			(43,070		)
Inventory		(3,023		)	—
Prepaid expenses		(91,035		)	(77,589		)
Accounts payable, trade		(1,265,310		)	(457,023		)
Other accrued expenses		31,771			(170,924		)
Accretion of asset retirement obligation		41,110			—
Asset retirement obligation incurred		(76,591		)	—
Net cash provided by operating activities		3,208,404			2,407,263
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property expenditures		(1,959,897		)	(5,841,308		)
Proceeds received from sale of oil and gas properties		533,142			2,579,389
Change in other assets		(207,164		)	1,220,225
Gas gathering and other equipment expenditures		(28,005		)	(34,291		)
Net cash used in investing activities		(1,661,924		)	(2,075,985		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from exercise of warrants and options		—			95,000
Proceeds from premiums payable		284,851			233,637
Repayment of premiums payable		(188,008		)	(163,405		)
Repayment of notes payable		(360,439		)	(9,558		)
Offering costs for preferred private placement		—			(7,258		)
Dividends paid		(334,445		)	(334,445		)
Acquisition of treasury stock		(8,255		)	—
Net cash used in financing activities		(606,296		)	(186,029		)
NET INCREASE IN CASH AND CASH EQUIVALENTS		940,184			145,249
CASH AND CASH EQUIVALENTS, at beginning of period		927,313			556,199
CASH AND CASH EQUIVALENTS, at end of period		$	1,867,497		$	701,448
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid for:
Interest		$	444,745		$	426,878
Income taxes		$	14,500		$	43,070
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Fair value of treasury stock issued for:
Oil and gas properties		$	—		$	170,267

 

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

 

5

 

CONDENSED 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 September 30, 2003 and the results of its operations and cash flows for the three and nine months ended September 30, 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, 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:

 

In August 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”).  The Company was required to adopt this new standard beginning 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

 

6

 

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 6%.  The transition adjustment resulting from the adoption of SFAS No. 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.

 

Subsequent to the implementation of SFAS No. 143, the Company recorded the following activity related to the liability for the nine months ended September 30, 2003:

 

 

Note 4.          STOCKHOLDERS’ EQUITY:

 

Options

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 will apply the fair value based method of accounting to such options.  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 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 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.

 

For the three and nine months ended September 30, 2003, the Company recognized compensation expense of $45,657 and $211,636, respectively, associated with its stock option grants.  The total number of options granted during the nine months ended September 30, 2003 was 595,083, as described more fully below.  The total number of shares covered by options expiring or cancelled during the nine months ended September 30, 2003 was 195,000.

 

During the nine months ended September 30, 2003, the Company issued non-qualified stock options covering 205,000 shares of common stock to attract certain new employees.  These options will equally vest over a three-year period beginning in 2004.  The options have exercise prices ranging from $.85 to $1.43 per share and will expire in 2013.

 

Additionally during this period, the Company issued qualified common stock options covering 289,583 shares of common stock to its directors for services rendered to the Company.  These options, granted under the Company’s incentive stock option plan, vested immediately and will expire in 2013.  The exercise prices, which were at least 110% of the Company’s common stock price on the date of grant, range from $1.00 to $1.56 per share.

 

The Company also issued qualified common stock options covering 100,000 shares of common stock to a Company officer, which will vest ratably over a three-year period beginning in 2004.  The options have

 

7

 

an exercise price of $1.00, which was in excess of the Company’s common stock price of $.87 per share at the grant date, and will expire in 2009.

 

An outside director returned qualified stock options covering 75,000 shares of common stock to the Company for cancellation.  The options were fully vested and had exercise prices of $10.00 per share (50,000 shares) and $5.22 per share (25,000 shares).

 

At September 30, 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 and nine months ended September 30, 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 SFAS No. 123 prospectively for all employee awards granted, modified or settled after January 1, 2003.  Therefore, the cost related to stock-based compensation included in the determination of income for the three and nine month periods ended September 30, 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 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.  The fair value of each grant is estimated on the date of grant using the Black-Scholes option-pricing model.

 

		FOR THE THREE MONTHS ENDED SEPTEMBER 30,						FOR THE NINE MONTHS ENDED SEPTEMBER 30,
		2003			2002			2003			2002
Net income (loss) applicable to common shareholders as reported		$	301,105		$	(490,273	)	$	249,556		$	(1,078,630	)
Add: Stock-based compensation expense included in reported net loss		45,657			—			211,636			—
Deduct: Total stock-based compensation expense determined under fair value method for all awards		(65,511		)	(37,515		)	(313,333		)	(194,516		)
Pro forma net income (loss) applicable to common shareholders		$	281,251		$	(527,788	)	$	147,859		$	(1,273,146	)
Income (loss) per share:
Basic – as reported		$	.02		$	(.04	)	$	.02		$	(.09	)
Basic – pro forma		$	.02		$	(.04	)	$	.01		$	(.10	)
Diluted – as reported		$	.02		$	(.04	)	$	.02		$	(.09	)
Diluted – pro forma		$	.02		$	(.04	)	$	.01		$	(.10	)

 

On June 20, 2003, at the Annual Shareholder Meeting the shareholders approved a proposal for the amendment to the Company’s 1999 Amended and Restated Incentive and Nonstatutory Stock Option Plan to increase the maximum number of shares of common stock that may be issued under the plan to 1,450,000 from 700,000, or a 750,000 share-increase.

 

8

 

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 nine-month period ended September 30, 2003, the Company purchased 10,750 shares for $8,255, or $.77 per share.  At September 30, 2003, the Company held 16,765 treasury shares with a market value of $23,806, or $1.42 per share.

 

Note 5.          NET INCOME (LOSS) PER COMMON SHARE:

 

		FOR THE THREE MONTHS ENDED SEPTEMBER 30,						FOR THE NINE MONTHS ENDED SEPTEMBER 30,
		2003			2002			2003			2002
Basic:
Net income (loss)		$	413,812		$	(377,566	)	$	584,001		$	(744,185	)
Less:  Preferred dividends		(112,707		)	(112,707		)	(334,445		)	(334,445		)
Net income (loss) applicable to common shareholders		$	301,105		$	(490,273	)	$	249,556		$	(1,078,630	)
Weighted average number of common shares		12,429,307			12,440,056			12,432,282			12,410,510
Basic earnings (loss) per share		$	.02		$	(.04	)	$	.02		$	(.09	)
Diluted:
Net income (loss) applicable to common shareholders		$	301,105		$	(490,273	)	$	249,556		$	(1,078,630	)
Add:  Preferred dividends		—			—			—			—
Net income (loss) for diluted earnings (loss) per share		$	301,105		$	(490,273	)	$	249,556		$	(1,078,630	)
Weighted average number of common shares		12,429,307			12,440,056			12,432,282			12,410,510
Common stock equivalent shares representing shares issuable upon exercise of stock options		87,022			Antidilutive			47,519			Antidilutive
Common stock equivalent shares representing shares issuable upon exercise of warrants		Antidilutive			Antidilutive			Antidilutive			Antidilutive
Common stock equivalent shares representing shares “as-if” conversion of preferred shares		Antidilutive			Antidilutive			Antidilutive			Antidilutive
Weighted average number of shares used in calculation of diluted income (loss) per share		12,516,329			12,440,056			12,479,801			12,410,510
Diluted earnings (loss) per share		$	.02		$	(.04	)	$	.02		$	(.09	)

 

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

 

 

Note 6.          LONG-TERM DEBT:

 

During the nine months ended September 30, 2003, the Company’s revolving credit agreement was re-determined and its maturity extended to April 1, 2005.  The $25,000,000 credit facility has a current borrowing base of $14,236,000, which is subject to an automatic monthly reduction of $88,000, which commenced July 31, 2003.  At September 30, 2003, the outstanding amount against the borrowing base was $13,284,652, which is collateralized by the Company’s oil and gas properties and gas gathering system and related assets.   At September 30, 2003, the effective interest rate, which is a LIBOR base rate plus 2.2%, was 3.32%.

 

Note 7.          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 investigate and determine the extent of groundwater contamination, if any.  In the second quarter of 2003, the third-party findings indicated no groundwater contamination and it was recommended to the proper regulatory agencies that no further assessment be required.  The cost for the investigation was approximately $400,000 and was covered by the Company’s pollution insurance.

 

Note 8.          DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

 

Natural Gas – During the nine months ended September 30, 2003, the Company settled certain outstanding commodity price hedging contracts, as set forth below, which 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.

 

 

10

 

For the contracts settled during the three and nine months ended September 30, 2003, the Company had realized losses of ($71,137) and ($1,105,469), respectively.  The impact of the natural gas hedges reduced the Company’s average natural gas price received for the three and nine months ended September 30, 2003 by $.16 per Mcf and $.81 per Mcf, respectively.  Based on the actual natural gas production for the nine months ended September 30, 2003, approximately 41% of the Company’s natural gas production was hedged for this period.

 

At September 30, 2003, there were no outstanding hedge contracts.

 

Crude Oil – During the nine months ended September 30, 2003, the Company settled certain outstanding commodity price hedging contracts, as set forth below, which covered 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.

 

 

For the contracts settled during the three and nine months ended September 30, 2003, the Company had realized losses of ($29,652) and ($231,375), respectively.  The impact of the crude oil hedges reduced the Company’s average crude oil price received for the three and nine months ended September 30, 2003 by $.82 per Bbl and $2.47 per Bbl, respectively.  Based on the actual crude oil production for the nine months ended September 30, 2003, approximately 32% of the Company’s crude oil production was hedged for this period.

 

At September 30, 2003, there were no outstanding hedge contracts.

 

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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 September 30, 2003 and December 31, 2002 and the results of operations for the three and nine-month periods ended September 30, 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 in 2003.  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.

 

12

 

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 nine months ended September 30,
		2003			2002
Beginning cash balance		$	927,313		$	556,199
Sources of cash:
Cash provided by operations		3,208,404			2,407,263
Cash provided by sales of oil and gas properties and equipment		533,142			2,579,389
Cash provided by financing activities		284,851			328,637
Total sources of cash including cash on hand		4,953,710			5,871,488
Uses of cash:
Oil and gas expenditures, net of prepaid drilling advances		(2,167,061		)	(4,621,083		)
Other asset expenditures		(28,005		)	(34,291		)
Cash used by financing activities		(891,147		)	(514,666		)
Total uses of cash		(3,086,213		)	(5,170,040		)
Ending cash balance		$	1,867,497		$	701,448

 

Our working capital was a surplus of $2,847,838 at September 30, 2003 compared to a deficit of ($721,859) at September 30, 2002 and a deficit of ($77,047) at December 31, 2002.  The significant increase in our working capital and liquidity for the nine months ended September 30, 2003 was due to lower oil and gas capital expenditures, an increase in cash flow from operations resulting from a higher natural gas and crude oil price environment, lower operating expense partially offset by an increase in general and administrative expense.  At September 30, 2003, we had no futures derivative liability associated with our future production volume compared to a futures derivative liability at September 30, 2002 and December 31, 2002 of $967,128 and $702,417, respectively.  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 the end of a month and may vary materially from month to month.

 

Our principal source of short-term liquidity is from internally generated cash flow.  With a higher level of capital expenditures expected for the last half of 2003, our growth in liquidity and working capital will not continue at the rate experienced for the first half of 2003.   Should natural gas and crude oil prices decrease materially, our current operating cash flow would decrease and our liquidity and working capital growth would be negatively impacted.

 

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 was re-determined and extended during the quarter ended June 30, 2003, has a maturity date of April 1, 2005 and a current borrowing capacity of $14,236,000 subject to an automatic monthly reduction of $88,000, which commenced on July 31, 2003.  At September 30, 2003, 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 3.32%.  We may reduce our current outstanding debt balance by an additional 3%, or $400,000 by the end of 2003 depending on cash availability.

 

13

 

Long Term Liquidity and Capital Resources

At September 30, 2003, we had no material long-term commitments associated with our capital expenditure plans or operating agreements except as noted in the following table.  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 drilling and acquisition activities in future periods, gas and oil price conditions and other related economic factors.  The following tables show our contractual obligations and commitments.

 

Contractual Obligations		Payments Due by Period
		Total			Less than 1 year			1-3 years			4-5 years			After 5 years
Notes payable (1)		$	13,441,888		$	157,236		$	13,284,652		$	—		$	—
Operating leases (2)		103,669			87,399			16,270			—			—
Drilling obligations (3)		432,075			432,075			—			—			—
Other (4)		56,250			56,250			—			—			—
Total cash obligations		$	14,033,882		$	732,960		$	13,300,922		$	—		$	—

 

(1)                         $13,284,652 is related to our current credit agreement with a commercial bank.

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

(3)                         Represents the remaining dry hole cost commitment under our Kansas drilling program.

(4)                         Represents amounts due under a financial advisory agreement.

 

Other Commercial Commitments		Amount of Commitment Expiration per Period
		Total			Less than 1 year			1-3 years		4-5 years		After 5 years
Standby letters of credit		$	176,000		$	176,000		—		—		—

 

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

 

Critical Accounting Policies and Estimates

The management’s discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP.  GAAP a comprehensive set of accounting and disclosure rules and requirements, the application of which requires our managements’ judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives.  The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amount of assets and liabilities and disclosure of contingent assets or liabilities, if any, at the date of the financial statements, and the reported amount of revenues and expenses during the reporting period.  We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances.  Actual results may differ from these estimates under different assumptions or conditions.  Note 1. to our 2002 audited consolidated financial statements included in the 2002 Annual and Form 10-K contain a comprehensive summary of our significant accounting policies.  The following is a discussion of our most critical accounting policies, judgments and uncertainties that are inherent in our application of GAAP:

 

Use of Estimates - The preparation of the our consolidated financial statements in conformity with GAAP 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

 

14

 

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 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%. 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 nine months ended September 30, 2003 unevaluated leasehold costs of $947,367 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. For the nine months ended September 30, 2003, costs of $54,137 were transferred to the U.S. evaluated costs, or full cost pool.

 

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.

 

Estimates of future dismantlement, restoration and abandonment costs – On January 1, 2003 with the mandated adoption of SFAS No. 143, the accrued future abandonment costs, which requires an estimate for each well, is based on type of production structure, reservoir characteristics, depth of the reservoir, market demand for equipment and currently available procedures.  Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the political and regulatory environment, proper discount rate and timing of abandonment.  For more information, please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 3. ASSET RETIREMENT OBLIGATION.

 

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 counter parties 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 West Edmond Hunton Lime Unit, that are “captive” to one natural gas purchaser due to the location of the production and lack of alternate natural gas sales outlets and purchasers.  In this particular instance, Duke Energy is the natural gas purchaser.

 

15

 

Plan of Operation for 2003

 

For the nine months ended September 30, 2003, we had capital expenditures and drilling prepayments of approximately $2.2 million.  The majority of the expenditures related to the following projects:

 

•                  $480,000 for the acquisition of additional working interest in certain non-operated properties in which we had existing interests.  Subsequent to the purchase of the 20% working interest, we sold the acquired interests for $530,000.

 

•                  $205,000 expended on the drilling and completion of the M.A. Failla No. 1, Broussard Field, Lafayette Parish, LA, which was tested in the first quarter of 2003 and commenced sales on September 30, 2003.  We have a 4.8% working interest in the well, increasing to approximately 10% working interest after well payout.  The well was producing approximately 15,000 gross Mcf (525 net Mcf) of natural gas and 400 gross barrels (14 net barrels) of condensate per day.

 

•                  $421,000 expended for drilling, completion, workovers and salt water conversion in the Brookshire Dome area, Waller County, TX.  We have participated in the drilling of 10 gross wells (1.3 net wells), of which seven gross wells (1.1 net wells) were successful, one gross well (.1 net well) was a dry hole and two gross wells (.3 net well) are in the completion process.

 

•                  $260,000 expended related to drilling and recompletion activity at WEHLU, Oklahoma County, OK.  To date three wells have been recompleted or stimulated and we have participated in the drilling of one gross well (.4 net well) that was completed subsequent to September 30, 2003.  The well is currently producing approximately 25 gross barrels (9 net barrels) per day and 300 gross Mcf (108 net Mcf) per day.

 

•                  $525,000 expended in our Kansas drilling program.  Approximately $396,000 was expended on acreage and seismic and approximately $129,000 has been incurred for drilling activity through September 30, 2003.  In July 2003, we committed to a 13-well drilling program located within a six-county area in the Mississippian subcrop belt of South Central Kansas, which covers approximately 13,500 gross acres.  We will participate in the program with a 35% working interest.  All of the prospects are at depths of approximately 5,000 feet with 11 of the 13 prospects classified as infill-development wells and the remaining two prospects classified as new field exploratory wells.  Eleven of these prospects possess primarily gas potential while the other 2 prospects have oil potential.  Drilling commenced during the 3^rd quarter of 2003, with the objective to have the majority, if not all, of the prospects drilled by the end of 2003.  The operator is a third party industry partner that is a well-known and established operator in the area.  At September 30, 2003, two gross wells (.7 net wells) have been drilled.  One well was successful and is in the completion stage while one well was plugged and abandoned subsequent to September 30, 2003.  Subsequent to September 30, 2003, four additional wells commenced drilling with one well currently in the completion process.

 

•                  $100,000 expended on drilling and recompletion activity in McIntosh County and Tulsa County, OK.  During the nine months ended September, we participated in the drilling of one gross well (.2 net well) that was successful.  Subsequent to September 30, 2003, we drilled two gross wells (1.4 net wells) in McIntosh County, OK, which are currently in the completion process.

 

16

 

In the last quarter of 2003, we anticipate incurring approximately $2.1 million in capital expenditures.  Funding for our capital program will be provided from internally generated cash flow.  The project areas and estimated expenditures for the remainder of the year are as follows:

 

• Mid-Continent
•  WEHLU, Edmond, OK - drilling and workovers			$	.5 million
•  South Central KS - drilling			.9 million
•  McIntosh County, OK - land and drilling			.1 million
• Texas
•  Brookshire Dome, Waller County, TX - drilling			.2 million
• Gulf Coast
•  Lapeyrouse Field, Terrebone Parrish, LA - drilling			.3 million
•  West Broussard, Lafayette Parish, LA– Failla #1 facilities			.1 million
Total			$	2.1 million

 

We are projecting our cash flows from operations, excluding changes in working capital, to be approximately $6.0 million based on a 2003 average natural gas price of $4.53 per Mcf and an average oil price of $25.87 per barrel and a 2003 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.  Additional cash flow from those wells that are drilling or scheduled to be drilled in 2003 is not considered in our current projection.

 

17

 

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 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.

 

18

 

Comparison of Results of Operations

 

Quarter ended September 30, 2003 and Compared to Quarter ended September 30, 2002

We had net income of $413,812 for the quarter ended September 30, 2003 compared to a net loss of ($377,566) for the same period ended 2002.  A significantly higher natural gas and crude oil price environment and lower operating expenses were the primary reasons for the increase in net income.  The increase was partially offset by a decrease in our natural production and higher general and administrative expense during the third quarter 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.

 

In Thousands		Quarter Ended September 30,						$ - Increase (Decrease)			% - Increase (Decrease)
		2003			2002
Net income (loss)		$	413.8		$	(377.6	)	$	791.4		(210	)
Oil and gas sales		3,145.7			2,238.4			907.3			41
Field service income		130.8			84.7			46.1			54
Lease operating expense		547.9			711.1			(163.2		)	(23	)
Production tax		188.9			153.2			35.7			23
Field service expense		50.6			50.5			.1			—
G&A expense		742.2			453.6			288.6			64
Depletion – Full cost		1,145.2			1,142.8			2.4			—
Depreciation – Field service and other		52.3			47.7			4.6			10
Interest expense		130.8			143.6			(12.8		)	(9	)
Production:
Natural Gas – MMcf		436.4			582.4			(146.0		)	(25	)
Crude Oil – MBbl		36.1			26.7			9.4			35
Natural Gas Equivalent – MMcfe		653.0			742.9			(89.9		)	(12	)
$ per unit:
Ave. gas price – Mcf		4.94			2.82			2.12			75
Ave. oil price – Bbl		27.40			22.35			5.05			23
Ave. operating expense – Mcfe		.84			.96			(.12		)	(12	)
Ave. production tax expense – Mcfe		.29			.21			.08			38
Ave. G&A – Mcfe		1.14			.61			.53			87
Ave. Depl. – Full cost – Mcfe		1.75			1.54			.21			14

 

For the quarter ended September 30, 2003, oil and gas sales increased $907,263 or 41%, from the same quarter ended 2002, to $3,145,698.  The increase for the quarter was a direct result of higher natural gas and crude oil prices.   Higher commodity prices resulted in an increase in oil and gas revenues of $1,109,276, with higher natural gas prices comprising 84% of the increase.  However, lower natural gas and crude oil production for the quarter ended September 30, 2003, as compared to the same quarter in 2002, partially offset this increase.  Our natural gas and crude oil production was 12% lower on an Mcf equivalent basis when compared to the same quarter in 2002.  Natural gas production was lower primarily due to natural production decline in our South TX, Lapeyrouse, LA and McIntosh County, OK properties.  This decrease was partially offset by higher crude oil production in the West Edmond Hunton Lime Unit (“WEHLU”), OK and Brookshire Dome, Waller County, TX areas that was a result of our recompletion and drilling activity in the nine months ended September 30, 2003.  Lower natural gas production volumes resulted in lower natural gas revenues of $411,201 partially offset by higher crude oil revenues of $182,314 associated with increased crude oil production.

 

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

 

19

 

volatility.  Hedges covered approximately 24% of our production on an equivalent MMbtu basis for the quarter ended September 30, 2003.  For the quarter ended September 30, 2003, the average sales price received for our natural gas was reduced by approximately $.16 per Mcf from our natural gas hedges and the average sales price received for our crude oil was reduced by approximately $.82 per Bbl from our crude oil hedges.  For further discussion please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.

 

Operating expenses, excluding production taxes, decreased $163,172 or 23%, to $547,920 for the quarter ended September 30, 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 $35,698, or 23%, for the quarter ended September 30, 2003 as compared to the same quarter ended in 2002, 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.

 

General and administrative expense for the three months ended September 30, 2003 increased $288,590 or 64%, to $742,207 compared to $453,617 for the same period in 2002.  The increase was due primarily to the following items:

 

 

Depletion and depreciation expense increased $7,094, or 1%, from the same period in 2002 to $1,197,554 for the three months ended September 30, 2003.  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 September 30, 2003 was $1.75 compared to $1.54 for the same period in 2002.  For the three months ended September 30, 2003, depreciation expense related to other assets increased slightly from the same period in 2002 to $52,310.  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.

 

Interest expense decreased for the nine months ended September 30, 2003, compared to the same period 2002, as a result of a lower outstanding debt balance and lower interest rates partially offset by $13,703 of accretion expense associated with our asset retirement obligation. There was no comparable accretion expense in 2002.

 

20

 

Nine Months ended September 30, 2003 and Compared to Nine Months ended September 30, 2002

We had net income of $584,001 for the nine months ended September 30, 2003 compared to a net loss of ($744,185) for the same period ended 2002.  A significantly higher natural gas and crude oil price environment and lower operating expenses were the primary reasons for the increase in net income.  The increase was partially offset by a decrease in our oil and gas production and higher general and administrative expenses during the first nine 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.

 

		Nine Months Ended Sept. 30						$ - Increase (Decrease)			% - Increase (Decrease)
In Thousands		2003			2002
Net income (loss)		$	584.0		$	(744.2	)	$	1,328.2		(178	)
Oil and gas sales		8,920.7			6,932.9			1,987.8			29
Field service income		499.7			281.0			218.7			78
Lease operating expense		1,657.0			2,066.5			(409.5		)	(20	)
Production tax		586.1			463.5			122.6			26
Field service expense		143.9			141.7			2.2			2
G&A expense		2,233.6			1,386.6			847.0			61
Depletion – Full cost		3,649.9			3,334.8			315.1			9
Depreciation – Field service and other		162.7			160.3			2.4			1
Interest expense		402.5			426.9			(24.4		)	(6	)
Production:
Natural Gas – MMcf		1,362.0			1,718.8			(356.8		)	(21	)
Crude Oil – MBbl		93.5			98.9			(5.4		)	(5	)
Natural Gas Equivalent – MMcfe		1,923.0			2,312.4			(389.4		)	(17	)
$ per unit:
Ave. gas price – Mcf		4.72			2.80			1.92			69
Ave. oil price – Bbl		26.60			21.45			5.15			24
Ave. operating expense – Mcfe		.86			.89			(.03		)	(3	)
Ave. production tax expense - Mcfe		.30			.20			.10			50
Ave. G&A – Mcfe		1.16			.60			.56			93
Ave. Depl. – Full cost – Mcfe		1.90			1.44			.46			32

 

For the nine months ended September 30, 2003, oil and gas sales increased $1,987,870, or 29%, from the same period in 2002, to $8,920,744.  The increase for the nine months 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 first quarter contributed significantly to the higher natural gas prices.  Lower national storage levels and supply uncertainty due to global events favorably impacted crude oil prices.  The higher commodity prices resulted in an increase in oil and gas revenues of $3,102,712, with higher natural gas prices comprising 84% of the increase.  However, lower natural gas and crude oil production for the nine months ended September 30, 2003, as compared to the same quarter in 2002, partially offset this increase.  Our natural gas and crude oil production was 17% lower, on an Mcf equivalent basis when compared to the same period in 2002.  The lower natural gas and crude oil production was primarily due to natural production decline associated with our South Texas, Brookshire, Lapeyrouse and coalbed methane properties.  Lower production volumes resulted in lower oil and gas sales of $1,114,842, with natural gas production volume comprising 90% 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 38% of our production on an equivalent MMbtu basis for the nine months ended September 30, 2003.  For the nine months ended September 30, 2003, the average sales price received for our

 

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natural gas was reduced by approximately $.81 per Mcf from our natural gas hedges and the average sales price received for our crude oil was reduced by approximately $2.47 per Bbl from our crude oil hedges.  For further discussion please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES.

 

Operating expenses, excluding production taxes, decreased $409,458, or 20%, to $1,657,028 for the nine months ended September 30, 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 $122,563, or 26%, for the nine months ended September 30, 2003 as compared to the same period ended in 2002, 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.

 

General and administrative expense for the nine months ended September 30, 2003 increased $847,046 or 61%, to $2,233,621 compared to $1,386,575 for the same period in 2002.  The increase was due primarily to the following items:

 

 

The $400,000 executive bonus related to the hiring of a new executive in late 2002 and was paid in the first and third quarters of 2003.  Compensation expense from stock options is the expense related to the issuance of common stock options issued to employees and directors during the nine months ended September 30, 2003.  On January 1, 2003, we adopted SFAS 123 (for further discussion, please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 4. STOCKHOLDERS’ EQUITY) and now recognize compensation expense based on the fair value of the stock options granted.  Legal expense increased due to increase activity related to filing reviews and the inclusion of a favorable $21,000 reimbursement adjustment related to a contract dispute in legal expense for the nine months ended 2002.  There was no comparable adjustment in the same period ended 2003.

 

Depletion and depreciation expense increased $317,466, or 8%, from the same period in 2002 to $3,812,592 for the nine months ended September 30, 2003.  Depletion associated with evaluated oil and gas properties comprised the total 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 nine months ended September 30, 2003 was $1.90 compared to $1.44 for the same period in 2002.  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.  There was not a significant difference in this expense for the periods ended September 30, 2003 and 2002.

 

Interest expense decreased for nine months ended September 30, 2003, compared to the same period 2002, as a result of lower interest rates and a lower outstanding debt balance partially offset by $41,110 of accretion expense associated with our asset retirement obligation. There was no comparable accretion expense in 2002.

 

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Income Taxes

As of September 30, 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.  Based on past results and current forecasts, we have established a valuation allowance to reduce net deferred taxes to zero.  There was no tax expense for the periods presented since the net operating loss carryforward offset net income for the nine months ended September 30, 2003.  There was no change in deferred taxes during the periods presented and we had no net deferred taxes at September 30, 2003.

 

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 that we use from time to time.  (For further information, please refer to PART I. FINANCIAL INFORMATION, Item 1.  Financial Statements, Note 8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES).  The counter party to our hedging agreements is a commercial bank.  Currently none of our future production is hedged and we may 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.

 

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 2. Changes in Securities

 

In August and September 2003, options to purchase a total of 70,000 shares of our common stock were issued to attract certain new employees.  These options, which have exercise prices ranging from $1.36 to $1.43, will vest over a three-year period and will expire in 2013.

 

In June and September 2003, options to purchase a total of 50,000 shares of our common stock were issued to two outside directors with exercise prices ranging from $1.50 to $1.56.  These options vested immediately and will expire in 2013.

 

The employees and directors 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 and directors 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 6.  Exhibits and Reports on Form 8-K

 

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

 

10.46	Operating Agreement dated July 31, 2003 and effective July 1, 2003, between Beta Operating Company, L.L.C. and Woolsey Petroleum relating to a 13 well drilling commitment.
10.47	Letter agreement dated July 9, 2003, between Beta Oil & Gas, Inc. and Petro Capital Advisors, L.L.C. relating to financial advisory services.
10.48	Letter agreement dated October 13, 2003 between Beta Oil & Gas, Inc. and Petro Capital Advisors, LLC amending certain terms under the July 9, 2003 letter agreement.
31.1	Certification of Periodic Report by Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Periodic Report by Chief Financial Officer under Section 302 of Sarbanes-Oxley Act of 2002
32.1	Certification of Periodic Report by the Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Periodic Report by the Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002

 

(b)         Reports on Form 8-K

 

Form 8-K dated August 14, 2003, which was furnished to the SEC on August 14, 2003, to report under Item 12.  the Company’s press release announcing its 2003 second quarter financial results.

 

Form 8-K dated August 19, 2003, which was furnished to the SEC on August 20, 2003, to report under Item 9.  the Company’s press release dated August 19, 2003, announcing its increase to its 2003 budget and operations update for the last half of 2003.

 

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

 

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