UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

 

 

WASHINGTON, D.C.  20549

 

 

FORM 10-K

 

 

 

BETA OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

 

Nevada		86-0876964
(State of Incorporation)		(I.R.S. Employer Identification No.)
6100 S. Yale, Suite 300, Tulsa, OK		74136
(Address of principal executive offices)		(Zip Code)
(918) 495-1011
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:    Common Stock, par value $.001 per share
			(Title of Each Class)

 

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).  o  Yes  ý No

 

The aggregate market value of such common stock held by non-affiliates was approximately $15,052,365 based on the reported closing sales price of $1.32 on the Nasdaq Market on June 30, 2003.

 

Check if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained within this form, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

 

As of March 16, 2004, 12,429,307 shares of the registrant’s common stock were outstanding.

 

Certain sections of the registrant’s proxy statement for the 2004 annual meeting of stockholders are incorporated by reference into Part III.  Certain sections of amendment no. 3 to the registrant's preliminary proxy statement filed on March 17, 2004 are incorporated by reference into Part I.

 

Exhibit index follows page F-35.

 

 

TABLE OF CONTENTS

 

PART I
Glossary of Terms
Disclosure Regarding Forward-Looking Statements
ITEM 1 & 2.	Business and Properties
ITEM 3.	Legal Proceedings
ITEM 4.	Submission Of Matters To A Vote Of Security Holders
PART II
ITEM 5.	Market For Registrant’s Common Equity And Related Stockholder Matters
ITEM 6.	Selected Financial Data
ITEM 7.	Management’s Discussion And Analysis of Financial Condition and Results of Operations
ITEM 7A.	Quantitative And Qualitative Disclosure About Market Risk
ITEM 8.	Financial Statements And Supplementary Data
ITEM 9.	Changes In And Disagreements With Accountants On Accounting And Financial Disclosure
ITEM 9A.	Controls and Procedures
PART III
ITEM 10.	Directors and Executive Officers of the Registrant
ITEM 11.	Executive Compensation
ITEM 12.	Security Ownership Of Certain Beneficial Owners And Management
ITEM 13.	Certain Relationships And Related Transactions
ITEM 14.	Principal Accountant Fees and Services
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules, And Reports On Form 8-K
Signatures
Exhibit Index

 

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GLOSSARY OF TERMS

 

We are in the business of exploring for and producing oil and natural gas.  Oil and gas exploration is a specialized industry.  Many of the terms used to describe our business are unique to the oil and gas industry.  We present the following glossary to clarify certain of these terms you may encounter while reading this Form 10-K.

 

“Acquisition costs of properties” means the costs incurred to obtain rights to production of oil and gas.  These costs include the costs of acquiring oil and gas leases and other interests.  These costs include lease costs, finder’s fees, brokerage fees, title costs, legal costs, recording costs, options to purchase or lease interests and any other costs associated with the acquisition of an interest in current or possible production.

 

“Area of mutual interest” or “AMI” means, generally, an agreed upon area of land, varying in size, included and described in an oil and gas exploration and exploitation agreement which participants agree will be subject to rights of first refusal as among themselves, such that any participant acquiring any minerals, royalty, overriding royalty, oil and gas leasehold estates or similar interests in the designated area, is obligated to offer the other participants the opportunity to purchase their agreed upon percentage share of the interest so acquired on the same basis and cost as purchased by the acquiring participant. If the other participants, after a specific time period, elect not to acquire their pro-rata share, the acquiring participant is typically then free to retain or sell such interests.

 

“Back-in interests” also referred to as a carried interest, involve the transfer of interest in a property, with provision to the transferor to receive a reversionary interest in the property after the occurrence of certain events.

 

“Bbl” means barrel, 42 U.S. gallons liquid volume, used in this annual report in reference to crude oil or other liquid hydrocarbons.

 

“Bcf” means billion cubic feet, used in this annual report in reference to gaseous hydrocarbons.

 

“Bcfe” means billions of cubic feet of gas equivalent, determined using the ratio of six thousand cubic feet of gas to one barrel of oil, condensate or gas liquids.

 

“Casing point” means the point in time at which an election is made by participants in a well whether to proceed with an attempt to complete the well as a producer or to plug and abandon the well as a non-commercial dry hole.  The election is generally made after a well has been drilled to its objective depth and an evaluation has been made from drill cutting samples, well logs, cores, drill stem tests and other methods.  If an affirmative election is made to complete the well for production, production casing is then generally cemented in the hole and completion operations are then commenced.

 

“Development costs” are costs incurred to drill, equip, or obtain access to proved reserves.  They include costs of drilling and equipment necessary to get products to the point of sale and may entail on-site processing.

 

“Exploration costs” are costs incurred, either before or after the acquisition of a property, to identify areas that may have potential reserves, to examine specific areas considered to have potential reserves, to drill test wells, and drill exploratory wells.  Exploratory wells are wells drilled in unproven areas.  The identification of properties and examination of specific areas will typically include geological and geophysical costs, also referred to as G&G, which include topological studies, geographical and geophysical studies, and costs to obtain access to properties under study.  Depreciation of support equipment, and the costs of carrying unproved acreage, delay rentals, ad valorem property taxes, title defense costs, and lease or land record maintenance are also classified as exploratory costs.

 

“Farmout” involves an entity’s assignment of all or a part of its interest in or lease of a property in exchange for consideration such as a royalty.

 

“Future net revenue, before income taxes” means an estimate of future net revenue from a property, based on the production of the proven reserves of oil and natural gas believed to be recoverable at a specified date, after deducting production and ad valorem taxes, future capital costs and operating expenses, before deducting income taxes. Future net revenue, before income taxes, should not be construed as being the fair market value of the property.

 

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“Future net revenue, net of income taxes” means an estimate of future net revenue from a property, based on the proven reserves of oil and natural gas believed to be recoverable at a specified date, after deducting production and ad valorem taxes, future capital costs and operating expenses, net of income taxes.  Future net revenues, net of income taxes, should not be construed as being the fair market value of the property.

 

“Gross” oil or gas well or “gross” acre is a well or acre in which an owner has a working interest.

 

“Mcf” means thousand cubic feet, used in this annual report to refer to gaseous hydrocarbons.

 

“Mcfe” means thousands of cubic feet of gas equivalent, determined using the ratio of six thousand cubic feet of gas to one barrel of oil, condensate or gas liquids.

 

“MMcf” means million cubic feet, used in this annual report to refer to gaseous hydrocarbons.

 

“MMbtu” means million British thermal units, used in this annual report to refer to the energy content associated with natural gas and crude oil.

 

“MBbl” means thousand barrels, used in this annual report to refer to crude oil or other liquid hydrocarbons.

 

“Net” oil and gas wells or “net” acres are determined by multiplying “gross” wells or acres by the owner’s working interest percentage in such wells or acres.

 

“Oil and gas lease” or “lease” means an agreement between a mineral owner, the lessor, and a lessee which conveys the right to the lessee to explore for and produce oil and gas from the leased lands.  Oil and gas leases usually have a primary term during which the lessee must establish production of oil and or gas.  If production is established within the primary term, the term of the lease generally continues in effect so long as production occurs on the lease.  Leases generally provide for a royalty to be paid to the lessor from the gross proceeds from the sale of production.

 

“Overpressured reservoir” is a reservoir subject to abnormally high pressure as a result of certain types of subsurface conditions.

 

“Present value of future net revenue, before income taxes” means future net revenue, before income taxes, discounted at an annual rate of 10% to determine the “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties.

 

“Present value of future net revenue, net of income taxes” means future net revenue, net of income taxes discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties.  Also known as the “Standardized Measure of Discounted Future Net Cash Flows” if SEC pricing assumptions are used.

 

“Production costs” means operating expenses and severance and ad valorem taxes on oil and gas production.

 

“Prospect” means a location where both geological and economical conditions favor drilling a well.

 

“Proved oil and gas reserves” are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made.  Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.  Reservoirs are considered proved if economic recovery by production is supported by either actual production or conclusive formation test.  The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can reasonably be judged as economically productive on the basis of available geological and engineering data.  In the absence of information on fluid contacts the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

 

“Proved developed oil and gas reserves” are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Additional oil and gas reserves expected to be obtained

 

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through the application of fluid injection or other improved secondary or tertiary recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed recovery program has confirmed through production response that increased recovery will be achieved.

 

“Proved undeveloped oil and gas reserves” are those proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.  Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled.  Proved reserves for other undrilled units are claimed only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.  Estimates for proved undeveloped reserves attributable to any acreage do not include production for which an application of fluid injection or other improved recovery technique is required or contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

 

“Reserve target” see “Prospect”.

 

“Royalty interest” is a right to oil, gas, or other minerals that is not burdened by the costs to develop or operate the related property.

 

“Seismic option” generally means an agreement in which the mineral owner grants the right to acquire seismic data on the subject lands and grants an option to acquire an oil and gas lease on the lands at a predetermined price.

 

“Trend” means a geographical area along which a petroleum pay occurs (fairway).

 

“Working interest” or “WI” is an interest in an oil and gas property that is burdened with the costs of development and operation of the property.

 

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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-K which address activities, events or developments, which we expect or anticipate, 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 section 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

•                  The proposed Petrohawk transaction described under PART I, Item 1. Business and Item 2. Properties – General, Petrohawk Transaction

 

We can give no assurance that our expectations and assumptions will prove to be correct.  The Petrohawk transaction is subject to approval by our stockholders at a special meeting which is expected to be held at the end of April or early May, 2004.  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 forward-looking statements are subject to various known and unknown risks, uncertainties and contingencies, many of which are beyond our control. Such things may cause actual results, performance, achievements or expectations to differ materially from what we anticipated.

 

Factors that may affect such forward-looking statements include, but are not limited to:

 

•                  Our ability to generate additional capital to complete our planned drilling and exploration activities

•                  Risks inherent in oil and gas acquisitions, exploration, drilling, development and production

•                  Oil and natural gas prices

•                  Competition from other oil and gas companies

•                  Shortages of equipment, services and supplies

•                  General economic, market or business conditions

•                  Economic, market or business conditions in the oil and gas industry and in the energy business generally

•                  Government regulation

•                  Environmental matters

•                  Financial condition and operating performance of the other companies participating in the exploration, development and production of oil and gas ventures that we are involved in

•                  Our failure to consummate the Petrohawk transaction

 

In addition, since some of our prospects are currently operated by third parties, we may not be in a position to control costs, safety and timeliness of work as well as other critical factors affecting a producing well or exploration and development activities.

 

5

 

PART I

 

Item 1.           Business and Item 2. Properties

 

GENERAL

We are an independent oil and gas company engaged in the exploration, exploitation, development, production and acquisition of natural gas and crude oil.  We are a Nevada corporation incorporated in June 1997.  Our operations are currently focused on the exploration and development of oil and gas producing trends situated in Oklahoma, Texas, Louisiana and Kansas.  Our Australian drilling concession expired in 2003.

 

At December 31, 2003, we owned interests in approximately 218 gross (181 net) producing wells, in the Mid-Continent, Texas and Louisiana regions and participated in the drilling and completion of 28 gross (7.0 net) wells during the year.  Additionally, we own interests in 57,099 net acres in Kansas, Louisiana, Oklahoma, Texas, and Offshore Louisiana State and Federal Waters.

 

Total proved reserve volumes at December 31, 2003 were 22.4 Bcf of natural gas and 1,307.5 MBbl of oil, or 30.2 Bcfe of natural gas compared to December 31, 2002 proved reserves of 14.7 Bcf of natural gas and 608.6 MBbl of oil or 18.3 Bcfe of natural gas.  Total 2003 proved reserves increased approximately 11.9 Bcfe, or 65%, from 2002 primarily due to: 1.) extensions or discoveries of approximately 7.5 Bcfe, 2.) reserve revisions of approximately 5.5 Bcfe due to performance and 3.) higher 2003 year end natural gas and crude oil prices compared to year end 2002 resulting in an increase of approximately 1.5 Bcfe.  Average net daily production for 2003 was 7.2 MMcfe, down 12% from 2002 levels.  At year-end 2003, the average net daily production was approximately 7.8 MMcfe, compared to 7.5 MMcfe from year end 2002 levels, up 4 percent.

 

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;

 

•                                          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 expected to be called at the end of April or early May 2004.

 

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 commited 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 pay off 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 the Houston, Texas area.

 

6

 

A more complete discussion of the Petrohawk transaction is contained in the section captioned “Proposal No. 1: The Petrohawk Transaction” in our preliminary proxy statement which we filed on March 17, 2004.  After the completion of the SEC review of our preliminary proxy statement, a definitive proxy statement will be filed with the SEC and is expected to be first sent to our stockholders at the end of March or beginning of April, 2004.

 

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

 

RISK FACTORS

The following risks relate specifically to the conduct of our business.  You should also refer to the information under the heading Forward Looking Statements on page 5.  These risk factors pertain to our business assuming that the Petrohawk transaction is not consummated.  For a discussion of the risk factors relevant to the Petrohawk transaction, you should refer to the section captioned “Proposal No. 1—The Petrohawk Transaction—Certain Risks Associated with the Proposed Petrohawk Transaction” in our preliminary proxy statement which was filed with the SEC on March 17, 2004.  This section is incorporated into this report by reference.  After the completion of the SEC review of our preliminary proxy statement, a definitive proxy statement will be filed with the SEC and is expected to be first sent to our stockholders at the end of March or beginning of April, 2004.

 

 

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•                                          our ability to participate in wells proposed to be drilled and the potential economic benefit that such wells might generate,

•                                          our plans for aggressive expansion of our exploration activities,

•                                          our ability to take advantage of opportunities to acquire interests in future projects on favorable terms, and

•                                          our financial condition.

 

 

•                                          reduce our operations and business activities,

•                                          forfeit our interest in wells that are proposed to be drilled,

•                                          farm-out our interest in proposed wells,

•                                          sell a portion of our interest in proposed wells and use the proceeds to fund our participation for a lesser interest, or

•                                          reduce our general and administrative expenses.

 

 

•                                          may not be available on terms that are advantageous to us,

•                                          would dilute the percentage stock ownership of existing stockholders if additional equity securities are issued to raise the additional financing, and

•                                          could result in the issuance of additional equity securities which may have better rights, preferences or privileges than are available with respect to shares of our common stock held by our existing stockholders.

 

BUSINESS STRATEGY

 

In the fourth quarter of 2002, our Board of Directors made the decision to shift our Company’s emphasis from higher risk exploration activities to lower risk exploitation and development opportunities.  To facilitate this change, the decision was made to bring in new management in order to build the technical capabilities of our company and develop a more conservative portfolio of projects.

 

David A. Wilkins was hired as our new President and CEO on October 21, 2002, and after his arrival conducted a review of the existing assets of the company.  Under his leadership our new mission statement is to exercise investment discipline in oil and gas projects while methodically building value for our shareholders.

 

There have been changes made in both our personnel and investment strategy.  In November 2002, our Houston office was closed and all geological and geophysical (G&G) activity was relocated to the Tulsa office.  This allowed us to centralize and better coordinate the operating, engineering and G&G functions.  As part of the new technical focus for the Company, in 2003 we hired a total of four engineering and G&G personnel for the Tulsa office.

 

In August of 2003, our management presented a five-year strategic plan to our board.  This plan established an objective of a compound annual growth rate over the five-year period for both reserves and production of 15% to 20%, to be achieved through organic growth of the existing asset base and acquisitions of new oil and gas reserves with development drilling opportunities.  Utilizing management’s price forecast, the estimated capital expenditures over the five-year period was $64 million, to be funded primarily through internally generated cash flow.  Under the plan, we would attempt to:

 

•                  Lower our debt to equity ratio to less than 40%;

•                  Keep our finding and development costs within an acceptable range of $.80 to $1.75 per Mcfe (as adjusted from time to time to reflect the current product pricing and reserve category mix);

•                  Maintain a well balanced portfolio of projects (from a risk standpoint);

•                  Maintain a reserve ratio of at least 60% natural gas to 40% crude oil; and

•                  Achieve acceptable annual growth rates through selected acquisition and development opportunities.

 

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This plan was presented prior to the commencement of negotiations with Petrohawk.  It is contemplated that material aspects of this plan will be implemented only if the Petrohawk transaction is not consummated.  If the Petrohawk transaction is consummated, we will have an entirely new management team and a substantial amount of immediately available capital for our operations and acquisitions.

 

Our main goal is to maximize our value through profitable growth in our oil and gas reserves and productive capacity.  We believe that our assets in the Mid-Continent region have not been fully developed and our focus in 2003 was to shift our efforts from the high-risk exploration projects in South Texas to lower-risk Mid-Continent exploitation projects.  We expect to continue this focus.  Our largest asset is the West Edmond Hunton Lime Unit (WEHLU) located primarily in Oklahoma County, Oklahoma, in which we have approximately a 98% ownership interest in 30,000 acres (Avalon Exploration, Inc. holds rights to participate in a continuous drilling program - please see WEHLU discussion below).  We believe that this asset has infill development potential that we began pursuing in 2003.  Accordingly, the largest portion of our 2004 capital budget will be expended on WEHLU.  We will further pursue additional development drilling opportunities in other areas, such as our Hitchita Field in McIntosh County, OK.  In 2003, we participated in the successful drilling of South Louisiana prospects in the Broussard and Lapeyrouse fields, with additional drilling expected in 2004.  Due to the high drilling costs and operational risks associated with the South Louisiana wells, our ownership position in these wells was much lower than in our Mid-Continent wells.  In 2003, we were not able to further evaluate our alternatives with our South Texas holdings, but believe that our geotechnical data covering this area has value.  In addition, we will continue to assess potential changes in our asset mix through acquisition of new properties and/or divestiture of non-strategic properties deemed to have limited upside potential.

 

CRUDE OIL AND NATURAL GAS OPERATIONS

Our principal properties consist of developed and undeveloped oil and gas leases and the reserves associated with these leases.  Generally, developed oil and gas leases remain in force so long as production is maintained.  Undeveloped oil and gas leaseholds are generally for a primary term of three to five years.  In most cases, the term of our undeveloped leases can be extended by paying delay rentals or by producing reserves that are discovered under those leases.  Our revolving credit facility is collateralized by our proved developed reserves associated with our oil and gas properties and gas gathering system.

 

The table below sets forth the results of our drilling activities for the periods indicated:

 

		Years Ended December 31,
		2003				2002				2001
		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive (1)		2		.39		5		0.62		19		4.40
Dry		1		.35		5		0.83		12		2.71
Total Exploratory		3		.74		10		1.45		31		7.11
Development Wells:
Productive (1)		18		4.34		8		1.84		14		3.23
Dry		7		1.94		3		0.58		4		0.63
Total Development		25		6.28		11		2.42		18		3.86
Total Wells:
Productive (1)		20		4.73		13		2.46		33		7.63
Dry		8		2.29		8		1.41		16		3.34
Total		28		7.02		21		3.87		49		10.97

 

(1) Although a well may be classified as productive upon completion, future production may deem the well to be uneconomical, particularly for exploration wells where there is little or no production history.

 

At December 31, 2003, four gross (.46 net) wells were either drilling or in the completion process.  Subsequent to December 31, 2003, drilling commenced on two gross (.66 net) wells which are currently in the completion and testing phase.

 

The following table sets forth a summary of the producing oil and gas wells and the developed and undeveloped acreage in which we owned an interest at December 31, 2003.  We have not included in the table acreage in which our interest is

 

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limited to options to acquire leasehold interests, royalty or similar interests. Shut-in wells currently not capable of production are excluded from the producing well information.

 

		Producing Wells								Acreage
		Oil				Gas				Developed				Undeveloped
		Gross		Net (1)		Gross		Net (1)		Gross		Net (2)		Gross		Net
Texas		26		4.69		41		5.64		24,080.6		1,604.7		14,152.2		3,810.1
Oklahoma		30		15.30		89		56.16		54,986.3		42,341.9		1,548.9		563.5
Louisiana		1		0.12		11		0.90		8,329.8		942.5		3,073.2		879.3
Kansas		17		15.05		3		2.35		4,987.5		4,006.0		7,243.5		2,951.2
		74		35.16		144		65.05		92,384.2		48,895.1		26,017.8		8,204.1

 

(1)                                  Net wells are computed by multiplying the number of gross wells by our working interest in the gross wells.

(2)                                  Net acres are computed by multiplying the number of gross acres by our working interest in the gross acres.

 

Approximately 9,320 gross acres and 3,198 net acres of unevaluated leasehold are scheduled to expire in 2004.  The Company may not extend or renew some or all of this leasehold due to condemnation by previous exploration activity or change in our strategic emphasis.

 

At December 31, 2003, we had proved reserves of 1,307.5 MBbls of oil and 22.4 Bcf of gas as estimated by Netherland Sewell & Associates, Inc., an independent engineering firm.  These reserves are located entirely within the United States.  The following table sets forth, at December 31, 2003, these reserves and the present value, discounted at an annual rate of 10%, of our future net revenues (revenues less production and development cost) attributable to these reserves.

 

		Proved Developed			Proved Undeveloped			Total Proved
Oil (Bbls)		984,465			323,084			1,307,549
Gas (Mcf)		19,623,963			2,776,154			22,400,117
Future Net Revenues (before income taxes)		$	85,213,500		$	15,813,600		$	101,027,100
Present value of Future Net Revenue (before income taxes)		$	47,547,300		$	10,940,700		$	58,488,000
Present value of Future Net Revenue (after income taxes)		$	40,153,118		$	9,206,262		$	49,359,380

 

The above figures do not reflect the estimated December 31, 2003 future net revenues and the present value of future net revenues, discounted at an annual rate of 10%, for our McIntosh, Oklahoma gathering system, which were $2,170,600 and $1,626,600, respectively, nor do they reflect the cash flows associated with asset retirement obligations.

 

For purposes of determining the above cash flows, estimates were made of quantities of proved reserves and the periods during which they are expected to produce.  Future cash flows were computed by applying year-end prices to estimated annual future production from our proved oil and gas reserves.  The year-end prices for crude oil and natural gas used in the estimation were $29.25 per Bbl, based on a December 31, 2003, West Texas Intermediate posted price, and $5.97 per MMbtu, based on a December 31, 2003, Henry Hub spot market price, respectively. These prices were adjusted by lease for quality or energy content, transportation fees and regional price differentials.  Future development and production costs were computed by applying year-end costs expected to be incurred in producing and further developing the proved reserves.  The estimated future net revenue was computed by application of a 10% per annum discount factor.  The calculations assume the continuation of existing economic, operating and contractual conditions.  Other assumptions of equal validity could give rise to substantially different results.

 

For additional information on our oil and gas reserves, please refer to Item 8. Financial Statements and Supplementary Data, Note 14. UNAUDITED SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION.

 

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Our oil and gas reserves are not subject to any long-term supply arrangement with foreign governments or authorities.  Our estimated reserves have not been filed with or included in reports to any federal agency other than the SEC and U.S. Department of Energy, FORM EIA-23, Annual Survey of Domestic Oil and Gas Reserves for 2003.

 

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 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.  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%, and the lower of cost or estimated fair value of unproved properties, net of tax considerations.  For further discussion please refer to Item 8. Financial Statements and Supplementary Data, Note 2. ACQUISITIONS, SALES AND OIL AND GAS OPERATIONS.

 

Capitalized costs of our evaluated and unevaluated properties at December 31, 2003, 2002 and 2001 are summarized as follows:

 

		December 31, 2003						December 31, 2002						December 31, 2001
		United States			Foreign			United States			Foreign			United States			Foreign
Capitalized costs- Evaluated properties		$	76,906,831		$	1,810,549		$	69,226,520		$	1,680,921		$	57,027,523		$	1,680,921
Unevaluated properties		1,294,212			—			4,453,326			129,279			12,872,623			128,820
		78,201,013			1,810,549			73,679,846			1,810,200			69,900,146			1,809,741
Less- Accumulated depreciation, depletion, amortization & impairment		(37,929,567		)	(1,810,549		)	(33,452,175		)	(1,681,270		)	(23,377,455		)	(1,681,270		)
		$	40,271,476		$	—		$	40,227,671		$	128,930		$	46,522,691		$	128,471

 

We commenced sales of oil and gas in 1999.  Our average sales price, oil and natural gas production volumes and average production cost for each Mcfe of natural gas production for the periods indicated were as follows:

 

 

The average oil and gas sales prices above reflect the impact of any hedges.  Our 2003 average natural gas price was reduced by $.59 per Mcf and average crude oil price was reduced by $1.80 per Bbl due to our hedges.  In 2002, the impact of hedges reduced our average natural gas price by $0.25 per Mcf and our average crude oil price by $1.76 per Bbl.

 

Location of Operations

Our current areas of operations and holdings include Oklahoma, Louisiana, Kansas and Texas.  The following discussion summarizes our present operations and properties, acreage position, results from 2003 and future plans.

 

Oklahoma

WEHLU

The West Edmond Hunton Lime Unit (WEHLU) is our largest asset, covering 30,000 acres (about 47 square miles) primarily in Oklahoma County, Oklahoma. The WEHLU Field, originally discovered in 1942, is the largest Hunton Lime

 

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Field in the state of Oklahoma.  The field has 55 oil and natural gas wells (22 currently producing) with stable production holding the entire unit. We hold a 98% working interest at WEHLU and we are the operator.  At December 31, 2003, WEHLU had proven reserves of approximately 20.3 Bcfe or approximately 67% of our total proven reserves.  WEHLU currently produces approximately 3.4 MMcfe per day or 45% of our current net production.

 

We have an agreement with Avalon Exploration, Inc. of Tulsa, Oklahoma (“Avalon”) to jointly test and develop additional production in WEHLU.  The area of mutual interest (AMI) to be evaluated by our agreement with Avalon covers 5,680 acres located in the Central-Northwest area of the field.

 

As of December 31, 2003, Avalon had drilled five wells in WEHLU under our agreement.  The first four wells, drilled under a “pilot” program with Avalon, resulted in one dry hole and three completions.  The first two “pilot” wells were drilled to test the productivity of the lower Hunton (Chimney Hill) formation in the western portion of the unit.  Of these two wells, one well was non-productive in the lower Hunton but was successfully re-completed in the Upper Hunton (Bois d’ Arc) formation.  The other well was plugged and abandoned.  The last two “pilot” wells were drilled and successfully completed in the Upper Hunton formation.  Avalon paid 100% of the drilling and completion costs for the “pilot” wells.  In the three successful “pilot” wells, we have a 30% working interest after the “pilot” program reaches payout.  We anticipate the pilot program to payout during 2004.  Under the "pilot" program we have a "look-back" right to participate with a 10% working interest after the wells were drilled and completed, if successful. To exercise the "look-back" right, we would reimburse Avalon 10% of its historical costs in the pilot wells at the exercise date of the right.  We elected not to exercise our “look-back” right to participate in the four “pilot” wells due to the excessive historical cost associated with the one dry hole.

 

Avalon also drilled their first “development” well in WEHLU during 2003.  This well was successfully completed in the Upper Hunton formation and we participated with a 40% working interest.

 

A summary of the current gross production resulting from the Avalon drilling at WEHLU is listed below:

 

Well		Program		Oil - Bbl per day		Gas – Mcf per day		Water – Bbl per day
Recount		Pilot		Dry Hole		—		—
Mable T		Pilot		10		216		280
Damogram		Pilot		46		283		220
Willey		Pilot		230		536		300
Court Reception		Development		37		204		327

 

Currently, we are negotiating with Avalon regarding the drilling of a water disposal well to reduce water disposal costs.  Avalon plans on drilling four wells in 2004.  We anticipate participating in the drilling of these wells.

 

We have committed approximately $2.9 million, or 58%, of our 2004 capital budget for drilling and re-working wells in the WEHLU area.  The focus will be as follows:

 

•                  Continue our reactivation program of selected shut-in wells;

•                  Application of new stimulation techniques to certain existing wells for production optimization;

•                  Participation in the Avalon drilling program; and

•                  Drilling of two wells outside of the Avalon AMI.

 

 

McINTOSH COUNTY

We hold approximately 13,572 gross (9,571 net) acres of oil and gas leases and have interests in 60 gross (36 net) wells.  We operate 43 of these wells in the N.E. Hitchita Field.  In 2003, we participated in the drilling of 4 gross (1.66 net) wells, of which two gross (.94 net) wells were successful completions, one gross (.68 net) well was a dry hole and one gross (.05 net) well is in the completion stage.  The current net daily production from the McIntosh area is approximately 1,745 gross (472 net) Mcf of natural gas.

 

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The gas produced is dry and is sold into a low-pressure gathering system of our subsidiary, Red River Field Services, L.L.C.  The gathering system presently includes approximately 40 miles of pipeline and is connected to 49 wells, including the wells in which we have an interest.  During 2003, our gas gathering system in this area had gathering revenues of approximately $648,200.

 

Louisiana

Since 1999, we have invested approximately $14.7 million in leases, seismic data collection and drilling in South Louisiana, both onshore and offshore.  Currently, we have production in the Lapeyrouse Field located in Terrebonne Parish, the Broussard Field located in Lafayette Parish as well as production in shallow waters of West Cameron Blocks 39 and 49 located offshore Cameron Parish.  We have working interests in 10 gross (.9 net) producing wells that have a current net daily production of 1.8 MMcfe of natural gas. Our working interest in the producing wells range from 2.0% to 16.7%.  We have leasehold positions in the West Broussard Field in Lafayette Parish and the Lapeyrouse Field in Terrebonne Parish.

 

LAPEYROUSE PROJECT

The Lapeyrouse Prospects are located in Terrebonne Parish, Louisiana where we have a leasehold position covering 2,632 gross (201 net) acres.  Within this acreage position, we have two proven undeveloped locations and two probable locations identified for future drilling.  During 2003, we participated in the drilling and completion of one gross (.03 net) well and one gross (.05 net) well in which drilling commenced in 2003 but was completed subsequent to December 31, 2003.  For 2004, we anticipate participating in the drilling of three wells in this area.

 

WEST BROUSSARD PROSPECT

The West Broussard Prospect is located in Lafayette Parish, Louisiana and covers approximately 1,126 gross (791 net) acres.   We began acquiring acreage offsetting two high-rate natural gas wells in 2001.  In 2002, two drilling units were created known as the “East” and “West” units.  Additionally in 2002, we sold down our leasehold position to industry partners in the East unit for $1,300,000 and certain promoted working and reversionary interests in future wells to be drilled in this unit and giving the industry partner an option to purchase an interest in the West unit.  In 2003, the M. A. Failla #1 well was drilled and completed on the East unit.  Currently, the well is producing approximately 17,900 gross (619 net) Mcf of natural gas and 440 gross (15 net) barrels of condensate per day.  We have a 4.8% working interest in this well, increasing to 10.1% working interest after well payout which is estimated to occur in the first quarter of 2004.

 

With the success of the M.A. Failla #1, additional development of the West unit will occur in 2004. Currently, the Montesano #1 (formerly known as the Landry #1) located in the West unit is permitted and scheduled to commence drilling late in the first quarter of 2004.  In October 2003, our partner notified us it elected not to exercise its option to drill a well in the West unit.  At that time, we had a working interest ownership in the West unit of approximately 83.6%.  Subsequent to December 31, 2003, we entered into an arrangement with three parties, whereby upon closing of the arrangement we will receive approximately $731,500 for approximately 74% of our working interest in the prospect.  Additionally, we will receive approximately $1.1 million in production payments from future net cash flow from the well, if successful, and will receive an additional 4.2% working interest after well payout.  Upon closing of the arrangement, we will have a 9.6% working interest in the well increasing to a 13.8 % working interest after well payout.

 

At December 31, 2001, the proven undeveloped reserves for the West Broussard prospect were 7.3 Bcf of natural gas and 122 MBbl of condensate, representing approximately 27% of our total proved reserves.  At December 31, 2002, the reserves were reclassified from the proved category to a less certain category due to unexpected water and sand production in the adjacent well.  Positive results from the M.A. Failla #1 supported revision of the classification of reserves back to the proved category at December 31, 2003. At December 31, 2003, our total net proved reserves for the Broussard field were 2.1 Bcf of natural gas and 45.1 MBbl of condensate, representing approximately 8% of our total net proved reserves.  For further discussion on reserves see Item 8.  Financial Statements And Supplementary Data, Note 2. ACQUISITIONS, SALES AND OIL AND GAS OPERATIONS and Note 14. UNAUDITED SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION.

 

Texas

JACKSON COUNTY

Jackson County Texas was the focal point of our exploration activities from 1997 until 2002.  We participated in four project areas, known as Texana, Formosa Grande, Ganado and BWC, to acquire proprietary 3-D seismic information on approximately 185,000 acres.  Drilling commenced on these properties in 1999 and resulted in a total of 28 (3.9 net) discoveries out of 45 (7.1 net) wells drilled to date.  The successful wells were shallow-to-deep Frio and Yegua tests.  We

 

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did not have a successful Deep Wilcox test.  Parallel Petroleum Corporation, Allegro Investments, Inc. and Sue Ann Production, Inc. operate the majority of our Jackson County properties and our participation levels have ranged from 12.5% to 25%.  We have spent approximately $19.7 million since inception on lease acquisition, seismic and drilling activity.  Currently, our average net daily production for Jackson County is approximately 715 Mcfe of natural gas, or 10% of our total net daily production.

 

In the fourth quarter of 2002, we decided to shift our emphasis from higher risk exploration activities to lower risk exploitation opportunities, focusing on areas where we are active as the operator.  We will continue our efforts to identify exploration prospects in Jackson County, however, due to the high risk profile of these prospects and the associated high drilling costs, we plan to sell down or farmout our interests in all future prospects.  We are evaluating ways to create additional value by exchanging our existing Jackson County 3-D seismic data for similar data in other areas, at no additional cost to our company.   Due to the results to date and our change in business strategy, we  have impaired the unevaluated costs, associated with seismic  for Jackson County in 2003 and 2002, for $1.6 million and $4.9 million, respectively, for a total of $6.5 million. These costs were transferred to our U.S. evaluated properties and included in our full cost pool.

 

Mexican Sweetheart Project

The prospect is located to the southeast of the Texana project and is a deep Yegua test, which was based on 3-D seismic data.   We have 360 gross (132 net) acres under lease and have a 36% working interest in the prospect.  We plan to sell down out interest in this prospect to industry partners and retain a carried interest and/or a reversionary interest.  The leases expire in the third quarter of 2004.

 

North Mexican Sweetheart

In 2001, we acquired a 100% interest in 2,120 acres to the north of our Mexican Sweetheart Project.  In 2002, we sold our acreage position for cash and a reversionary interest of 12.5% after pay out in the exploratory well.  In 2003, a dry hole was drilled in offsetting acreage.  As such, plans to drill the prospect were cancelled and the remainder of the prospect costs were impaired and transferred to the U.S. domestic cost pool.

 

WHARTON COUNTY

King Louie

In 2001, we acquired a 100% interest in 1,229 acres in Wharton County, Texas.  Subsequent drilling on nearby acreage resulted in an apparent Wilcox discovery.  In 2003, we exchanged 50% of our interest in the prospect to a third party operator who paid 100% of the 2003 delay rentals, which were approximately $46,000.  The operator is currently seeking additional partners to drill the prospect.  Subsurface geology and seismic work is underway to better delineate the prospect.  The acreage position expires in the third quarter of 2004.

 

WALLER COUNTY

Brookshire Dome

The Brookshire Dome field is a salt dome field located approximately 30 miles west of Houston in Waller County, Texas.  Beta acquired interests in existing production in the Brookshire Dome area in mid-2001.    Based on the success of a shallow Miocene play south of our acreage block, an intensive drilling program was initiated in the second half of 2001 which targeted similar shallow Miocene oil and gas sands above the salt dome.  The potential also exists for deeper sub-salt Yegua and Wilcox objectives.  To date we have leased approximately 4,613 gross (440 net) acres for both exploration and exploitation opportunities.

 

Revere Corporation and Johnson Sanford are the operators of the wells in which we have an interest.  Revere is currently very active in drilling the shallow Miocene targets and under the agreement in place, we have the option to either participate or farm out on a well-by-well basis.  In 2003, we sold down certain of our working interests to Revere.  Under the terms of the sale, Revere is responsible for funding the drilling of four shallow exploration wells and two deep exploration wells.  We received a 6.25% carried working interest in the shallow wells and 12.5% carried interest in the deep wells on the drilling costs associated with these wells.  As of December 31, 2003, Revere had drilled all four shallow exploratory wells and one of the deep exploratory wells.  The shallow wells were successful and completed as producing wells, while the deep well was a dry hole. Revere plans to drill the second deep exploratory well in 2004.  We participated in the drilling of 10 gross (1.1 net) wells of which eight gross (.91 net) wells were successful.  Currently, we have interests in 27 gross (5.2 net) wells at Brookshire Dome.  Our total current daily average production is 912 gross (100 net) Mcf of natural gas and 1,106 gross (162 net) Bbl of oil.  The net amount expended to date in the Brookshire Dome area is $3.7 million.

 

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GALVESTON COUNTY

Greens Lake Project

The Rubel #1 (known as the Sara White Prospect), operated by Ocean Energy, was spuded in the fourth quarter of 2001 and completed during the second quarter of 2002.  A production test was performed and the well tested at a flow of 2.1 MMcf per day of natural gas and 30 Bbls of condensate per day.  The well commenced sales in August 2002, after a considerable delay due to right-of-way issues regarding the sales line.  Due to water encroachment, the production quickly declined to uneconomic levels.  The operator attempted to eliminate the water in the initial zone (“S” sand) but was unsuccessful. Subsequent recompletions up hole were also unsuccessful.  In mid-2003, the operator farmed out the well to another third party operator, who desired to re-enter the well and attempt recompleting certain zones that could potentially be prospective.  To date there have been no positive results.  If successful, we would have a 28.7% interest in the well but no further capital risked for the attempted re-entry.  If the current project to restore production is unsuccessful, the leases for this prospect will expire.  We originally had a 31% working interest in this well and our net expenditure was approximately $2.8 million.

 

RED RIVER AND LAMAR COUNTIES

The Detroit Project

In 2003, considerable effort was expended, along with an industry partner who had a similar acreage position in this area, in marketing this prospect for drilling.  However the effort was not successful.  The Detroit prospect, a large NE-SW trending seismically controlled feature in the Northwestern portion of Red River County and Eastern Lamar County in Northeast Texas, covered 9,401 gross (7,050 net) acres.  The high-risk exploration prospect was developed as a rework of existing seismic data and an extensive radiometric survey of the entire area for surface detection of hydrocarbons.  The majority of the original leases was consummated in 2000 and had primary lease terms ranging from two to three years.  The remainder of the existing leases expired in 2003.  Our total cost for acreage, seismic and other geological and geophysical activity was approximately $880,000.

 

SEASONALITY OF BUSINESS

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans.  Demand for natural gas is typically higher in the fourth and first quarters resulting in higher natural gas prices.  Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of results, which may be realized on an annual basis.

 

MARKETS AND CUSTOMERS

Our oil and gas production is sold at the well site on an as-produced basis at market-related prices in the areas where the producing properties are located.  We do not refine or process any of the oil or natural gas we produce.  Approximately 97% of our production is sold to unaffiliated purchasers on a month-to-month basis.

 

In the table below, we show the purchasers that each accounted for 10% or more of our revenue during the specified years.

 

		2003		2002		2001
Duke Energy Field Services, LLC		33	%	31	%	29	%
Allegro Investments		10	%	14	%	16	%
Sunoco, Inc.		10	%	9	%	7	%

 

We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce.  Other purchasers are available in our areas of operations.

 

The marketability of our oil and gas reserves, or of reserves which we may acquire or discover, may be affected by numerous factors beyond our control.  These factors include fluctuations in product markets and prices, the proximity and capacity of pipelines to our oil and gas reserves, our ability to finance exploration and development costs and the availability of processing equipment.  Additional factors are engineering and construction delays, difficulties and hazards resulting from unusual or unexpected geological or environmental conditions, or to the conditions involved in drilling and operating wells.

 

We are not obligated to provide a fixed and determinable quantity of oil or natural gas under any existing arrangements or contracts.  We expect to use hedge arrangements on a limited basis as necessary to partially protect against commodity price volatility.

 

Our business does not require us to maintain a backlog of products, customer orders or inventory.

 

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COMPETITIVE CONDITIONS IN THE BUSINESS

The petroleum and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources.  Many of these companies explore for, produce and market petroleum and natural gas, as well as, carry on refining operations and market the resultant products on a worldwide basis.  The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, and obtaining purchasers and transporters of the oil and gas we produce.  There is also competition between petroleum and natural gas producers and other industries producing energy and fuel.  Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments (and/or agencies thereof) of the United States and Canada; however, it is not possible to predict the nature of any such legislation and/or regulation which may ultimately be adopted or its effects upon our future operations.  Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil and gas and may prevent or delay the commencement or continuation of a given operation.  The exact effect of these risk factors cannot be accurately predicted.

 

OPERATIONAL RISKS

Oil and gas exploration and development involves a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome.  There is no assurance that we will discover or acquire additional oil and gas in commercial quantities.  Oil and gas operations also involve the risk that well fires, blowouts, equipment failure, human error and other circumstances that may cause accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment, or cause significant injury to persons or property may occur.  In such event, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could substantially reduce available cash and possibly result in loss of oil and gas properties.  Such hazards may also cause damage to or destruction of wells, producing formations, production facilities and pipeline or other processing facilities.

 

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive.  A loss not fully covered by insurance could have a materially adverse effect on our financial position and results of operations.

 

REGULATIONS

Domestic exploration for, and production and sale of, oil and gas are extensively regulated at both the federal and state levels.  Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden.  Also, numerous departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and gas industry that often are costly to comply with and that carry substantial penalties for failure to comply.  In addition, production operations are affected by changing tax and other laws relating to the petroleum industry, constantly changing administrative regulations and possible interruptions or termination by government authorities.

 

State regulatory authorities have established rules and regulations requiring permits for drilling operations, drilling bonds and reports concerning operations.  Most states in which we operate also have statutes and regulations governing a number of environmental and conservation matters, including the unitization or pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells.  Many states also restrict production to the market demand for oil and gas.  Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced from our properties.

 

We are subject to extensive and evolving environmental laws and regulations.  These regulations are administered by the United States Environmental Protection Agency (“EPA”) and various other federal, state, and local environmental, zoning, health and safety agencies, many of which periodically examine our operations to monitor compliance with such laws and regulations.  These regulations govern the release of waste materials into the environment, or otherwise relating to the protection of the environment, human, animal and plant health, and affect our operations and costs.  In recent years, environmental regulations have taken a “cradle to grave” approach to waste management, regulating and creating liabilities for the waste at its inception to final disposition.  Our oil and gas exploration, development and production operations are subject to numerous environmental programs, some of which include solid and hazardous waste management, water protection, air emission controls, and situs controls affecting wetlands, coastal operations, and antiquities.

 

Environmental programs typically regulate the permitting, construction and operations of a facility.  Many factors, including public perception, can materially impact the ability to secure an environmental construction or operation permit.  Once operational, enforcement measures can include significant civil penalties for regulatory violations regardless of intent.  Under appropriate circumstances, an administrative agency can request a “cease and desist” order to terminate operations.

 

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New programs and changes in existing programs are anticipated, some of which include Natural Occurring Radioactive Materials (“NORM”), oil and gas exploration and production waste management, and underground injection of waste materials.

 

Each state in which we operate has laws and regulations governing solid waste disposal, water and air pollution.  Many states also have regulations governing oil and gas exploration, development and production operations.

 

We are also subject to Federal and State Hazard Communications (“OSHA”) and Community Right to Know (“SARA Title III”) statutes and regulations.  These regulations govern record keeping and reporting of the use and release of hazardous substances.  We believe we are in compliance with these requirements in all material respects.

 

We may be required in the future to make substantial outlays to comply with environmental laws and regulations.  The additional changes in operating procedures and expenditures required to comply with future laws dealing with the protection of the environment cannot be predicted.

 

EMPLOYEES

As of the date of this annual report, we employ 12 full-time employees. We hire independent contractors on an “as needed” basis.  We have no collective bargaining agreements with our employees.  We believe that our employee relationships are satisfactory.

 

PREMISES

In January 2004 our office lease expired.  Under that arrangement, we leased approximately 6,400 square feet in Tulsa, Oklahoma, which included office and storage space and required a monthly payment of approximately $9,300.  We currently have entered into a short-term lease arrangement for approximately 7,200 rentable square feet that requires a monthly payment of approximately $10,770.  The lease term covers the period March 1, 2004 to April 30, 2004 and may be continued on a month-to-month basis.  All of our corporate functions and some operational functions are conducted from this site.  This arrangement will terminate should the Petrohawk transaction be consummated.  For further discussion of the Petrohawk transaction, see Item 1. Business and Item 2. Properties —GENERAL— Petrohawk transaction above.

 

We also maintain two field offices, of which one is located in south Tulsa County, Oklahoma and the other is located in Edmond, Oklahoma.

 

Item 3.           Legal Proceedings

 

None

 

Item 4.           Submission of Matters to a Vote of Security Holders

 

No matters were submitted to a vote of our shareholders during the fourth quarter of the fiscal year ended December 31, 2003.

 

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PART II

 

Item 5.    Market Price for Registrant’s Common Equity and Related Stockholder Matters

Our common stock began trading July 9, 1999 on the Nasdaq Small Cap Market under the symbol “BETA”.  On May 4, 2000 we were accepted on the Nasdaq National Market.  The following table sets forth for the fiscal periods indicated the range of the high and low bid prices of our common stock as reported on the Nasdaq National Market for each quarter in those periods.  We have not paid any cash or other dividends, other than those dividends associated with our preferred stock, since inception.  For the foreseeable future, we intend to retain any funds otherwise available for dividends.

 

		High			Low
2003
1st Quarter		$	1.07		$	.69
2nd Quarter		1.65			.62
3rd Quarter		1.52			1.15
4th Quarter		2.36			1.30
2002
1st Quarter		$	5.30		$	3.26
2nd Quarter		4.20			2.01
3rd Quarter		2.20			1.11
4th Quarter		1.31			0.80

 

Approximately 193 shareholders of record and approximately 3,110 beneficial owners as of March 16, 2004 held the common stock.  In many instances, a registered shareholder is a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.

 

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Item 6.           Selected Financial Data

 

Summary Financial Information for Beta

The following tables presents selected historical financial data derived from our Financial Statements as well as selected historical quarterly financial data.  The following data is only a summary and should be read with our historical financial statements and related notes contained in this document.  The acquisition of Red River Energy, Inc. in 2000 affects the comparability between the Financial Data for the periods presented.

 

		For the years ended December 31,
		2003			2002			2001			2000			1999
Income Statement Data:
Operating revenues		$	12,924,689		$	9,647,841		$	13,656,521		$	8,357,867		$	1,199,480
Operating expense (1)		3,359,239			3,500,351			3,808,523			1,516,113			81,538
General and administrative		3,082,605			2,209,887			2,679,121			2,141,005			1,418,240
Impairment expense		129,279			5,163,689			13,805,035			—			1,224,962
Depreciation and depletion expense		4,857,597			5,120,572			5,176,897			2,693,439			914,233
Interest expense		476,078			558,297			867,835			393,008			2,966,651
Net income (loss)		967,497			(6,881,612		)	(9,046,084		)	1,425,565			(5,384,403		)
Earnings (loss) per share:
Basic		$	.04		$	(.59	)	$	(.75	)	$	.13		$	(.66	)
Diluted		.04			(.59		)	(.75		)	.13			(.66		)
Weighted average common shares and equivalent outstanding:
Basic		12,431,530			12,417,957			12,368,373			10,616,692			8,160,000
Diluted		12,506,835			12,417,957			12,368,373			11,281,413			8,160,000
Balance sheet data:
Working capital		$	1,896,502		$	(77,047	)	$	(103,550	)	$	3,533,237		$	2,034,268
Total assets		46,115,243			44,753,260			52,629,378			58,466,152			20,881,475
Total long term debt		13,284,652			13,634,652			13,648,727			13,814,034			27,939
Stockholder’s equity		29,269,615			28,048,137			35,874,474			40,060,406			20,588,237
Proved Reserves
Oil (Mbbls)		1,307.5			608.6			836.8			814.0			13.2
Gas (MMcf)		22,400.5			14,688.2			24,710.0			19,418.0			4,170.0
Total (MMcfe)		30,245.4			18,320.0			29,730.8			24,302.8			4,249.2
Present value of estimate future net revenues before income tax discounted at 10%		$	58,488,000		$	35,929,439		$	31,295,012		$	100,199,288		$	6,012,972
Standardized measure (2)		$	48,333,104		$	35,929,439		$	31,295,012		$	71,458,654		$	6,012,972

 

(1)          Operating expense includes production taxes and field service expense associated with our McIntosh gathering system.

(2)          Includes reduction of $1,026,276 for asset retirement obligation.

 

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SELECTED QUARTERLY FINANCIAL DATA

 

		For the quarter ended
(In Thousands of Dollars except for per share amounts)		March 31			June 30			September 30			December 31
2003
Revenues		$	3,101.2		$	3,042.7		$	3,276.5		$	3,504.3
Revenues less operating expense		2,265.6			2,278.8			2,489.0			2,532.0
General and administrative expense		813.8			677.6			742.2			849.0
Net income (loss)		(16.8		)	187.0			413.8			383.5
Earnings (loss) per share:
Basic		(.01		)	.01			.02			.02
Diluted		(.01		)	.01			.02			.02
2002
Revenues		$	2,343.2		$	2,547.6		$	2,323.2		$	2,433.8
Revenues less operating expense		1,563.1			1,570.8			1,408.4			1,605.2
General and administrative expense		475.4			457.6			453.6			823.3
Net income (loss)		(206.2		)	(160.4		)	(377.6		)	(6,137.4		)
Earnings (loss) per share:
Basic		(.03		)	(.02		)	(.04		)	(.50		)
Diluted		(.03		)	(.02		)	(.04		)	(.50		)
2001
Revenues		$	4,696.1		$	3,809.6		$	2,531.3		$	2,619.5
Revenues less operating expense		3,748.5			2,926.5			1,623.7			1,549.3
General and administrative expense		570.2			682.8			611.2			814.9
Net income (loss)		905.7			388.0			(4,657.0		)	(5,682.9		)
Earnings (loss) per share:
Basic		.07			.03			(.39		)	(0.46		)
Diluted		.07			.03			(.39		)	(0.46		)

 

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Item 7.                                   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 December 31, 2003 and 2002, and the results of operations for the years ended December 31, 2003, 2002 and 2001.

 

Overview

In 2003, we saw an improvement in our overall financial condition due to: 1.) an increase in our cash flow provided from operations which was a result of a favorable commodity price environment during 2003, 2.) a successful exploration, exploitation and development capital program resulting in a 65% net increase in our proved reserves, and 3.) an increase in our exit daily production rate from 7.5 Mcfe at December 31, 2002, to 7.8 Mcfe at December 31, 2003.  Conversely, our total 2003 production volume decreased approximately 12% from 2002 and our general administrative expenses increased from 2002 by approximately 39%.  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 imports/exports, weather trends, power generation and industrial demands.

 

The discussion in this section regarding 2004 and subsequent periods are all subject to the effects of consummating the proposed transaction which is discussed in Item 1. Business and Item 2. Properties — GENERAL — Petrohawk Transaction.

 

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 years indicated.

 

		For the years ended December 31,
		2003			2002			2001
Beginning cash balance		$	927,313		$	556,199		$	1,536,186
Sources of cash:
Cash provided by operations		5,998,306			2,977,752			9,047,095
Cash provided by financing activities		284,852			328,637			6,822,927
Cash provided by sales of oil & gas properties and  Equipment		549,287			3,231,944			1,082,524
Total sources of cash including cash on hand		7,759,758			7,094,532			18,488,732
Uses of cash:
Oil and gas expenditures, net of prepaid drilling advances		(4,259,534		)	(5,442,418		)	(15,653,461		)
Other equipment		(52,022		)	(36,103		)	(177,103		)
Cash used by financing activities		(1,338,521		)	(688,698		)	(2,101,969		)
Total uses of cash		(5,650,077		)	(6,167,219		)	(17,932,533		)
Ending cash balance		$	2,109,681		$	927,313		$	556,199

 

Our working capital was a surplus of $1,896,502 at December 31, 2003, compared to a deficit of ($77,047) at December 31, 2002.  The significant increase in our working capital and liquidity for the twelve months ended December 31, 2003, was due to 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 and lower oil and gas capital expenditures.  Additionally, at December 31, 2003, we had no futures derivative liability associated with our future production volume compared to a futures derivative liability at December 31, 2002, of $702,417, 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.

 

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

 

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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 a current borrowing capacity of $13,972,000 subject to an automatic monthly reduction of $88,000, which commenced on July 31, 2003.  At December 31, 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 3.37%.  During 2003, we reduced our outstanding debt balance by $350,000 which was lower than projected.  Due to unplanned expenditures associated with the pending Petrohawk transaction as discussed further below, additional voluntary paydowns to the outstanding debt were deferred.

 

For the twelve months ended December 31, 2003, we expended approximately $4.2 million (including changes in prepaid drilling advances) primarily comprised of:

 

•                  $1.2 million related to our South Central Kansas drilling program - Approximately $.4 million was expended on acreage and seismic and approximately $.8 million has been incurred for drilling activity through December 31, 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 have a 35% working interest in the program.  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.  Drilling commenced during the 3^rd quarter of 2003 and to date, 13 gross  (4.55 net) wells have been drilled, with seven gross (2.45 net) wells deemed successful, four gross  (1.4 net) wells were dry holes and two gross (.7 net) wells drilling or in the completion stage.  Currently, five gross (1.75 net) wells are producing a total of approximately 940 gross (270 net) mcfe of natural gas per day.  Four gross (1.4 net) wells are awaiting pipeline connection.

 

•                  $.8 million expended on recompletion and drilling activity at WEHLU, Oklahoma County, OK.  To date seven gross (6.9 net) wells have been recompleted or stimulated and we have participated in the drilling of one gross (.4 net) well that was completed subsequent to the fourth quarter of 2003.  The new well is currently producing approximately 25 gross (8 net) barrels per day and 300 gross (96 net) Mcf per day.  We estimate that our daily production has increased by approximately 28 gross (22 net) barrels and 185 gross (145 net) Mcf from our recompletion and remediation activity.

 

•                  $.5 million expended for drilling, completion, workovers and conversion to salt water disposal in the Brookshire Dome area, Waller County, TX.  In 2003, we participated in the drilling of 10 gross (1.1 net) wells, of which eight gross (.91 net) wells were successful, two gross (.2 net) well were dry holes. Our current daily production rate from this activity is approximately 879 gross (100 net) Mcf of natural gas and 258 gross (59 net) Bbl of oil.

 

•                  $.4 million 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 is currently producing approximately 17,900 gross (619 net) Mcf of natural gas and 440 gross (15 net ) Bbl of condensate per day.

 

•                  $.3 million expended on drilling and recompletion activity in McIntosh County and Tulsa County, OK.  During the twelve months ended December 31, 2003, we participated in the drilling of four gross (1.6 net) wells in McIntosh County, OK of which two gross (.9 net) wells were successful, one gross (.7 net) well was a dry hole and one gross (.05 net) well is awaiting completion.  Currently, the two successful wells are producing 268 gross (88 net) Mcf of natural gas per day.

 

•                  $.4 million expended on the drilling and completion of two prospects located in the Lapeyrouse field, Terrebonne Parish, Louisiana.  We participated with a 3.1% working interest in the A.M. Dupont #2, which was a successful development well and is currently producing approximately 4,050 gross (90 net) Mcf of natural gas and 52 gross (1 net) Bbl of condensate per day.  Subsequent to December 31, 2003, the J.C. Dupont was successfully completed in which we have a 4.1% working interest.  The well is currently producing approximately 1,055 gross (31 net) Mcf of natural gas per day.

 

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•                  $.2 million expended on other projects with minority interest in South Texas.  Those projects included a participation with a 2.4% working interest in an exploratory well located in Wharton County, TX which was a dry hole and a recompletion attempt in the Rubel #1 located in Galveston County, TX  which was also unsuccessful.

 

On December 12, 2003, we entered into a securities purchase agreement with Petrohawk pursuant to which Petrohawk has agreed to a cash investment of $60,000,000 in our common stock, warrants and a convertible note.  Subject to approval by our shareholders, we will receive $25,000,000 for the issuance of 15,151,515 shares of our common stock and five-year common stock purchase warrants exercisable at a price of $1.65 per share.  Additionally, we 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 our 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 paying off the existing outstanding debt, acquisitions of oil and gas properties, future development and exploitation of existing and acquired oil and gas properties and exploration activity.

 

Long Term Liquidity and Capital Resources

We have no material long-term commitments associated with our capital expenditure plans or operating agreements.  Consequently, we have a significant degree of flexibility to adjust the level of such expenditures as circumstances warrant.  The level of capital expenditures will vary in future periods depending on the success we have with our exploratory drilling activities in future periods, gas and oil price conditions and other related economic factors.  The following tables show our contractual obligations and commitments.

 

Contractual Obligations		Payments Due by Period
		Total			Less than 1 year			1-3 years			4-5 years			After 5 years
Long – Term Debt (1)		$	13,919,147		$	515,263		$	13,403,884		$	—		$	—
Operating Leases (2)		93,848			72,351			21,497
Other (3)		37,500			37,500			—			—			—
Total cash obligations		$	14,050,495		$	625,114		$	13,425,387		$	—		$	—

 

(1)                         $13,851,577 represents principal and interest related to our current credit agreement with a commercial bank.  For further information please refer to Item 8. Financial Statements and Supplementary Data, Note 4, 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		$	176,500		$	176,500		—		—		—

 

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

 

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

 

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Plan of Operation for 2004

 

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).  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 natural gas price of $4.02 per Mcf, as adjusted for basis differentials, and an average spot crude oil price of $24.95 per barrel and 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 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 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;

 

28

 

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

 

Oil and gas properties - We account for our oil and gas producing activities using the full cost method of accounting as prescribed by the 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 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.  In 2003, unevaluated leasehold costs and related brokerage fees of $1,705,998 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 producing areas or wells and risk that estimate by 50-75%.  As mentioned

 

29

 

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 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.

 

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 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

Year ended December 31, 2003 and Compared to Year ended December 31, 2002

We had net income of $967,497 for the twelve months ended December 31, 2003 compared to a net loss of ($6,881,612) 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.  Our results of operations for 2002 included a fourth quarter full cost ceiling impairment of $5,163,689.

 

The following table summarizes key items of comparison and their related increase (decrease) for the twelve months ended December 31 for the periods indicated.

 

In Thousands		Years Ended December 31,						$ - Increase (Decrease)			% - Increase (Decrease)
		2003			2002
Net income (loss)		$	967.5		$	(6881.6	)	$	7,849.1		(114	)%
Oil and gas sales		12,276.5			9,244.5			3,032.0			33	%
Field service income		648.2			403.3			244.9			61	%
Operating expense		2,404.9			2,772.2			(367.3		)	(13	)%
Production tax expense		769.1			532.8			236.3			44	%
Field service expense		185.3			195.4			(10.1		)	(5	)%
G&A expense		3,082.6			2,209.9			872.7			39	%
Depletion – Full cost		4,671.1			4,911.0			(239.9		)	(5	)%
Depreciation – Field service and other		186.5			209.5			(23.0		)	(11	)%
Impairment expense		129.3			5,163.7			(5,034.4		)	(97	)%
Interest expense		476.1			558.3			(82.2		)	(15	)%
Income tax provision		(24.0		)	—			(24.0		)	—
Production:
Natural Gas – Mcf		1,859.1			2,249.4			(390.3		)	(17	)%
Crude Oil – Bbl		128.8			124.7			4.1			3	%
Natural Gas Equivalent – Mcfe		2,631.9			2,997.6			(365.7		)	(12	)%
$ per unit:
Ave gas price per Mcf		$	4.71		$	2.91		$	1.80		62	%
Ave oil price per Bbl		27.36			21.68			5.68			26	%
Ave operating expense per Mcfe		.91			.92			(.01		)	(1	)%
Ave production tax expense per Mcfe		.29			.18			.11			64	%
Ave G&A per Mcfe		1.17			.74			.43			59	%
Ave Depl per Mcfe		1.77			1.64			.13			8	%

 

For the twelve months ended December 31, 2003, oil and gas sales increased $3,031,965, or 33%, from the same period in 2002, to $12,276,495.  The increase for the twelve 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, supply uncertainty due to global events and a weaker U.S. dollar, which impacts the OPEC basket price, favorably impacted crude oil prices.  The higher commodity prices resulted in an increase in oil and gas revenues of $4,077,702, with higher natural gas prices comprising 82% of the increase.  However, lower natural gas volume for the twelve months ended December 31, 2003, as compared to the same period in 2002, partially offset this increase.  Our natural gas production was 17% lower 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 Oklahoma coalbed methane properties.  Lower natural gas production volumes resulted in a reduction to natural gas sales of $1,134,855.  Our crude oil production volume for the twelve months ended December 31, 2003 was 3% higher when compared to the same period in 2002.  The increase in production was a result of our drilling activity in the Brookshire Dome, Texas properties and drilling and recompletion activity on the WEHLU, Oklahoma properties.

 

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 hedges on a limited basis to lessen the impact of price volatility.  Hedges covered approximately 28% of our production on an equivalent MMbtu basis for the year ended December 31, 2003.  For the twelve months ended December 31, 2003, the average sales price received for our natural gas was reduced by approximately $.59 per Mcf from our natural gas hedges

 

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and the average sales price received for our crude oil was reduced by approximately $1.80 per Bbl from our crude oil hedges.  For further discussion please refer to Item 8. Financial Statements and Supplementary Data, Note 7,DERIVATIVE AND HEDGING ACTIVITIES.

 

Based on our natural gas production for the twelve months ended December 31, 2003, a decline in the average natural gas price realized by Beta of $1.00 per Mcf would have resulted in an approximate $1.3 million reduction in net income before income taxes.

 

Operating expenses, excluding production taxes, decreased $367,256, or 13%, to $2,404,897 for the twelve months ended December 31, 2003 compared to the same period for 2002.  The decrease was primarily due to lower operating expense associated with the Brookshire Dome, Texas properties, the Peace Creek and Zenith Field, Kansas properties and the 2002 divestment of certain low margin non-core properties.  Lower expenses in the Brookshire Dome area were primarily due to lower salt water disposal expense as a result of injection well availability and lower workover expense in 2003 on the Wade Crawford #1 and Kathleen Pickett #1.

 

Production tax expense increased $236,320, or 44%, for the twelve months ended December 31, 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 twelve months ended December 31, 2003 increased $872,718, or 39%, to $3,082,605 compared to $2,209,887 for the same period in 2002.  The increase was due primarily to the following items:

 

Description		2003 increase over 2002
Bonus related to 2002 executive hiring		$	400,000
Accrued 2003 employee bonuses		238,079
Compensation expense from stock options		237,130
Directors’ fees		103,500
Reserve for bad debt expense		(150,791		)
Total		$	827,918

 

The $400,000 executive bonus related to the hiring of a new chief executive officer in late 2002 and was paid in the first and third quarters of 2003.  Bonuses approved by our Compensation Committee were awarded to the employees for 2003 but were not paid until February 2004 and accordingly were accrued in 2003.  Compensation expense from stock options is the expense related to the issuance of common stock options issued to employees and directors during 2003.  On January 1, 2003, we adopted SFAS 123 (for further discussion, please refer to Item 8. Financial Statements and Supplementary Data,Note 8. STOCKHOLDERS’ EQUITY) and now recognize compensation expense based on the fair value of the stock options granted.  Directors’ fees increased in 2003 primarily due to the increased activity related to the proposed Petrohawk transaction in the fourth quarter of 2003.  In 2002, we recorded a reserve for bad debt expense related to the uncertainty of recoupment of a portion of a gas contracts settlement.  There was no comparable expense in 2003.

 

At December 31, 2003, we had approximately $245,000 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 cost at that time.  These deferred costs were recorded as a reduction to our paid in capital at December 31, 2003.

 

Depletion and depreciation expense decreased $262,975, or 5%, from the same period in 2002 to $4,857,597 for the twelve months ended December 31, 2003.  Depletion associated with evaluated oil and gas properties comprised 90% 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.  Lower production volumes for 2003, as compared to 2002, and a lower depletion rate for the fourth quarter due a significant increase in our December 31, 2003 reserves from our December 31, 2002 proved reserves were the primary reasons for the decrease in depletion expense.  However, the total decrease in depletion expense was partially offset due primarily to a decrease in our December 31, 2002 proved reserves related to our West Broussard prospect, which increased our depletion rate per Mcfe for the first nine months of 2003 to $1.90 as compared to $1.44 for the same period in 2002.  Depreciation expense for other assets

 

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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 twelve month periods ended December 31, 2003 and 2002 was $186,536 and $209,540, respectively.

 

At December 31, 2002, we recorded a non-cash impairment charge of $5,163,689 on our U.S. domestic evaluated properties due to the transfer of $4,883,031 from unevaluated properties related to our Jackson County, Texas area.  Additionally, our proved reserves decreased in the fourth quarter of 2002 due to the reclassification of the proved undeveloped reserves associated with the West Broussard prospect, to a less certain reserve category.  There was no comparable impairment for our U.S. domestic evaluated properties in 2003.

 

In the fourth quarter of 2003, the Company transferred 100% of the costs associated with a drilling concession in West Queensland Australia in which the Company owns a 25% working interest to our foreign evaluated properties.  The concession expired at December 31, 2003 and the operator of the concession  has applied for a re-extension but at this date no formal extension has been granted by the Australian government.  The prospect remains active but due to the uncertainty for the renewal of the concession the Company elected to charge 100% of the costs to impairment expense in 2003.  The amount transferred and impaired was $129,279.

 

Interest expense decreased for twelve months ended December 31, 2003, compared to the same period 2002, as a result of lower interest rates and a lower outstanding debt balance.

 

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Year ended December 31, 2002 and Compared to Year ended December 31, 2001

We had a reported net loss of ($6,881,612) for the year ended December 31, 2002 compared to a net loss of ($9,046,084) for the same period ended 2001.  Our results of operations for 2002 included a fourth quarter full cost ceiling impairment of $5,163,689, net of income tax while our 2001 results of operations included a full cost ceiling impairment of  $9,950,308, net of income tax.  Lower commodity prices and production volumes also contributed to the net loss for 2002.

 

The following table summarizes key items of comparison and their related increase (decrease) for the twelve months ended December 31 for the periods indicated.

 

 

In Thousands		Years Ended December 31,						$ - Increase (Decrease)			% - Increase (Decrease)
		2002			2001
Net income (loss)		$	(6,881.6	)	$	(9,046.1	)	$	2,164.5		(24	)%
Oil and gas sales		9,244.5			12,788.1			(3,543.6		)	(28	)%
Field service income		403.3			868.4			(465.1		)	(54	)%
Operating expense		2,772.2			2,589.7			182.5			7	%
Production tax expense		532.8			879.5			(346.7		)	(39	)%
Field service expense		195.4			339.3			(143.9		)	(42	)%
G&A expense		2,209.9			2,679.1			(469.2		)	(18	)%
Depletion – Full cost		4,911.0			4,858.4			52.6			1	%
Depreciation – Field service and Other		209.5			318.5			(109.0		)	(34	)%
Impairment expense		5,163.7			13,805.0			(8,641.3		)	(63	)%
Interest expense		558.3			867.8			(309.5		)	(36	)%
Income tax – (provision) benefit		—			3,504.4			(3,504.4		)	—
Production:
Natural Gas – Mcf		2,249.4			2,512.5			(263.1		)	(10	)%
Crude Oil – Bbl		124.7			114.3			10.4			9	%
Natural Gas Equivalent – Mcfe		2,997.6			3,198.3			(200.7		)	(6	)%
$ per unit:
Ave gas price per Mcf		$	2.91		$	3.97		$	(1.06	)	(27	)%
Ave oil price per Bbl		21.68			24.72			(3.04		)	(12	)%
Ave operating expense per Mcfe		.92			.81			.11			14	%
Ave production tax expense per Mcfe		.18			.27			(.09		)	(33	)%
Ave G&A per Mcfe		.74			.84			(.10		)	(12	)%
Ave Depl per Mcfe		1.64			1.52			.12			8	%

 

For the year ended December 31, 2002, oil and gas sales decreased $3,543,585 or 28%, from the year ended 2001, to $9,244,530.  The decrease resulted from lower commodity prices and lower natural gas production.  The lower commodity prices resulted in a decrease in revenue of approximately $2,758,573 or 78% of the total decrease from 2001.  Lower natural gas prices comprised 86% of the total price decrease with lower crude oil prices accounting for the remaining 14%.   Lower natural gas production volumes resulted in lower 2002 revenues, when compared to 2001, of $1,043,349 partially offset by higher 2002 crude oil production.  The increase in 2002 crude oil production, from 2001 production, resulted in increased revenues of $258,338.  Natural gas sales volumes were lower for the twelve months ended December 31, 2002 compared to the same period ended 2001, primarily due to lower production in our South Texas shallow Frio wells and West Cameron Block 49 wells partially offset by production from the T. Cenac #1 well, located in the Lapeyrouse field, Terrebonne Parish, Louisiana.  The lower production was due to natural decline in the South Texas wells and water production in the West Cameron Block 49 wells, which were reworked and restored to production late in the third quarter of 2002.  Increased crude oil production was primarily due to new production associated with our exploration activity in the Brookshire Dome area in Waller County, Texas and the T. Cenac #1.

 

Generally, we sell our natural gas to various purchasers on an index-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 54% of our production on an equivalent MMbtu basis for the year ended December 31, 2002.  Based on our natural gas production for the twelve months ended December 31, 2002, a decline in the average natural gas price realized by Beta of $1.00 per Mcf would have resulted in an approximate $2.1 million reduction in net income before income taxes.

 

Operating expenses, excluding production taxes, increased $182,435, or 7%, to $2,772,153 for the year ended December 31, 2002 compared to the same period for 2001. The increase was related to our Brookshire Dome, Waller County, Texas

 

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properties, in which activity commenced in the last half of 2001.  2002 production tax expense decreased $346,708 from 2001 due to lower oil and gas revenues.  Production taxes are generally assessed as a percentage of gross oil and/or gas revenues received.

 

General and administrative expenses for the twelve months ended December 31, 2002 decreased approximately  $469,234, or 18%, to $2,209,887 compared to $2,679,121 for the same period in 2001.  The decrease was primarily due to lower personnel costs, including salaries from personnel reductions, outside services, legal, travel and insurance expense.  Additionally, the twelve-month period ended December 31, 2001 included a non-recurring charge of $205,415 relating to a settlement of a gas contract dispute.  General and administrative expense for 2002 included non-recurring items of 1.) Executive separation compensation of approximately $157,000, 2.) $50,000 executive signing bonus related to our new President and 3.) Bad debt expense of $155,000 related to the recoupment of a portion of the gas contract settlement previously discussed.

 

Depletion and depreciation expense decreased $56,325, or 1%, from the same period in 2001 to $5,120,572 for the twelve months ended December 31, 2002. Depletion associated with evaluated oil and gas properties increased $52,668 when compared to 2001.  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 to a decrease in our proved reserves related to the West Broussard prospect, as previously discussed, our per Mcfe depletion rate for the twelve months ended December 31, 2002 was $1.64 compared to $1.52 for the same period in 2001.  For the twelve months ended December 31, 2002, depreciation expense related to other assets decreased $108,993 from the same period in 2001 to $209,540.  The decrease was related to the depreciation expense associated with the gathering assets, which is calculated on a “unit of revenue” method.  The “unit of revenue” method amortizes the capitalized costs associated with the gathering assets based on the ratio of gross actual revenues for the current period to the total remaining gross revenues for the gathering assets. Therefore, the lower gross gathering revenues for the twelve months ended December 31, 2002 resulted in lower depreciation expense for the period.

 

At December 31, 2002, we recorded a non-cash impairment charge of $5,163,689 on our U.S. domestic evaluated properties due to the transfer of $4,883,031 from unevaluated properties related to our Jackson County, Texas area.  Additionally, our proved reserves decreased in the fourth quarter of 2002 due to the reclassification of the proved undeveloped reserves associated with the West Broussard prospect, to a less certain reserve category.  The average prices used for the reserve estimation at December 31, 2002 were $4.84 per Mcf for natural gas and $29.53 per barrel for crude oil.  In 2001, the total capitalized costs for our U.S. evaluated properties full cost pool exceeded the net realizable value of the properties and, accordingly, impairment write-downs of  $7,034,925 and $6,770,110, were recorded in the three-month periods ended December 31, 2001 and September 30, 2001, respectively.  The impairments were due mainly to the significant decline in the price of natural gas and crude oil from December 31, 2000 and higher future operating expenses regarding production on the older properties.  The average prices used in the determination of the net realizable value at December 31, 2001 and September 30, 2001 were $2.65 and $2.20 per Mcf, respectively, for natural gas and $18.17 and $23.50 per barrel, respectively, for crude oil.  The prices used at December 31, 2000 for the impairment test were $10.14 per Mcf for natural gas and $26.06 per barrel for crude oil.

 

Interest expense decreased for twelve months ended December 31, 2002, compared to the same period 2001, as a result of lower interest rates.

 

Income Taxes

 

As of December 31, 2003, we had available, to reduce future taxable income, a U.S. federal regular net operating loss (‘NOL”) carryforward of approximately $23,627,576, and a U.S. federal alternative minimum tax NOL carryforward of approximately $21,255,782, which expire in the years 2018 through 2023.  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.  We also had various state NOL carryforwards totaling approximately $5,311,670 at December 31, 2003, with varying lengths of allowable carryforward periods ranging from five to 20 years and can be used to offset future state taxable income.  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.  We had no deferred income taxes at December 31, 2003.

 

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Related Party Transactions

 

In 2001, the Company entered into an Exploration and Development Area of Mutual Interest Agreement in Fremont County, Wyoming with a director of the Company.  The Company purchased certain geology and lease acreage approximating 1,627 acres in a prospect located therein for $154,800.  The Company acquired a 75% working interest with the director retaining a 25% working interest and up to a 5% overriding royalty interest.  All future exploration and development costs will be shared accordingly with the Company being responsible for 75% and the director responsible for 25% of such costs.  During 2001, the Company incurred additional costs of approximately $166,600.  In connection with the review of its unevaluated properties for impairment, the Company recorded an impairment of $127,229 based on remaining lease term.

 

Mr. Robert E. Davis, Jr., director and Chairman of the Company’s Board of Directors, has overriding royalty interests in certain of the Company’s oil and gas properties, which were acquired from Red River Energy, LLC (“Red River”) in September 2000.  Mr. Davis, former Executive Vice President and Chief Financial Officer of Red River, received the overriding royalty interests as part of his compensation while employed at Red River, prior to its merger with the Company.  Mr. Davis received approximately $49,800 in royalty income from Beta properties during 2003.

 

Director Rolf N. Hufnagel, director since June 20, 2003, and his wife have overriding royalty interests in certain of our oil and gas properties that were acquired from Red River in September 2000. Mr. Hufnagel received the overriding royalty interests as part of his compensation while employed at Red River. Mr. Hufnagel  and his wife, collectively, received approximately $136,300 in royalty income from Beta properties during 2003.

 

Impact of Recently Issued Standards

In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51 and revised this interpretation in December 2003 (“FIN 46”).  FIN 46 requires the consolidation of variable interest entities by their primary beneficiary if the variable interest entities do not effectively disperse risks among the parties involved.  Previously, entities were generally consolidated by an enterprise when it had a controlling financial interest through ownership of a majority of voting interest in the entity.  The adoption of FIN 46 had no impact on our financial position or results of operations.

 

On April 30, 2003, the FASB issued Statement of Financial Accounting Standards No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS 149”).  SFAS 149 is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to SFAS 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features.  SFAS 149 was effective for contracts entered into or modified after June 30, 2003, and hedging relationships designated after June 30, 2003.  The adoption of SFAS 149 had no impact on our financial position or results of operations.

 

On May 15, 2003, the FASB issued Statement of Financial Accounting Standards No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (“SFAS 150”).  SFAS 150 establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity.  SFAS 150 must be applied immediately to instruments entered into or modified after May 31, 2003, and to all other instruments that exist as of the beginning of the first interim financial reporting period beginning after June 15, 2003.  Early adoption of SFAS 150 is not permitted.  The adoption of SFAS 150 had no impact on our financial position or results of operations.

 

Item 7A.  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.    Through the third quarter of 2003, we hedge a portion of our production using costless collars and swaps and we may use such instruments in the future to hedge our production.  At December 31, 2002, the fair value of these derivatives was a liability of $702,417.  Based on the actual production for the twelve months ended December 31, 2003, approximately 30% of our natural gas production and approximately 23% was hedged for 2003.  At December 31, 2003, we had no outstanding hedges due to a projected strong market for both natural gas and crude oil.  For more information please refer to Item 8.  Financial Statements and Supplementary Data, Note 7. DERIVATIVE AND HEDGING ACTIVITIES.

 

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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 December 31, 2003, 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 $45,500 for 2003 and approximately $49,600 for 2002.

 

Item 8.                                   Financial Statements and Supplementary Data.

 

Our financial statements and supplementary financial data, which begin on page F-1, are included elsewhere in this report.

 

Item 9.                                   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

On May 5, 2003, we appointed Ernst & Young, LLP (“EY”) as independent auditors to perform the audit of our financial statements for fiscal year 2003.  The appointment was effective June 20, 2003 with the ratification by our shareholders.  The decision was made by our audit committee of our board of directors and approved by the entire board.  It was our desire and need to have independent auditors with an office and presence in Tulsa, Oklahoma where our corporate office is located.  Our prior auditors, HEIN & Associates LLP (“HEIN”), do not maintain a Tulsa office and the HEIN representatives with whom we dealt were located in Orange, California.  HEIN remained our independent auditors until June 20, 2003.

 

There were no disagreements with HEIN on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of HEIN, would have caused it to make reference thereto in its report on our financial statements for such time periods.  Also during those time periods, there were no “reportable events” as such term is used in Item 304(a)(1)(v) of Regulation SK.

 

Item 9A.                          Controls and Procedures

 

Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this report on  Form 10-K are effective to ensure that information required to be disclosed by us in reports that we file or submit 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 fourth fiscal quarter of the fiscal year covered by this report on Form 10-K, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

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PART III

 

Item 10.  Directors And Executive Officers Of The Registrant.

 

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2004 annual meeting under the headings “Proposal One — Election of Directors,” “Executive Officers”, “Section 16(a) Beneficial Ownership Reporting Compliance” and “Code of Ethics”.

 

Item 11.  Executive Compensation

 

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2004 annual meeting under the heading “Executive Compensation.”

 

Item 12.  Security Ownership Of Certain Beneficial Owners And Management

 

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2004 annual meeting under the heading “Principal Stockholders and Security Ownership of Management.”

 

Item 13.  Certain Relationships And Related Transactions

 

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2004 annual meeting under the heading “Certain Transactions.”

 

Item 14.  Principal Accountant Fees and Services

 

The information required to be contained in this Item is incorporated by reference to our definitive proxy statement to be filed with respect to our 2004 annual meeting under the heading “Ratification of Appointments of Independent Auditors.”

 

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PART IV

 

Item 15.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K

 

(a)    (1) Financial Statements:

The financial statements of the Company and its subsidiaries and report of independent public accountants listed in the accompanying Index to Financial Statements are filed as a part of this Form 10-K

 

(2) Financial Statements Schedules:

All schedules are omitted because they are inapplicable or because the required information is contained in the financial statements or included in the notes thereto.

 

(3) Exhibits:

The following documents are included as exhibits to this Form 10-K.

 

 

EXHIBIT NUMBER		DESCRIPTION
3.1		Original Articles of Incorporation of Registrant as amended on March 19, 1998, incorporated by reference to Exhibit 3.1 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
3.2		Certificate of Amendment of Articles of Incorporation of the Registrant, dated August 28, 2000, incorporated by reference to Exhibit 3.1 of Beta’s Annual Report of Form 10-K filed for the year ended December 31, 2000.
3.3		Amended and Restated Bylaws of the Registrant, dated June 20, 2003, incorporated by reference to Exhibit 3.01 of Beta’s Second Quarter 2003 Form 10-Q filed August 13,2003.
4.1		Form of Warrant Agreement covering warrants issued to employees as employment inducements.
4.2		Warrant Agreement between Beta and Brookstreet Securities dated July 30, 1999.
4.3		Form of Warrant Agreement with suppliers, service providers and other third parties.
4.4		Certificate of Designation of Beta Oil & Gas, Inc.'s 8% Cumulative Convertible Preferred Stock, incorporated by reference to Exhibit 3.1 of Beta's Form 8-K filed on July 3, 2001.
4.5		Warrant Agreement between Beta and its preferred shareholders, including Warrant Certificates A and B, incorporated by reference to Exhibit 4.1 of Beta's Form 8-K filed on July 3, 2001.
10.1		Formosa Grande Prospect Agreement, Dated August 1, 1997, incorporated by reference to Exhibit 10.1 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
10.2		Texana Prospect Agreement, Dated July 15, 1997, incorporated by reference to Exhibit 10.2 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
10.3		Ganado Prospect Agreement, Dated November 1, 1997, incorporated by reference to Exhibit 10.3 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998..
10.4		Lapeyrouse Prospect Agreement, Dated October 13, 1997, incorporated by reference to Exhibit 10.5 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
10.5		Rozel (Transition Zone) Prospect Agreement, Dated February 24,1998, incorporated by reference to Exhibit 10.6 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
10.6		Steve Antry Employment Agreement, Dated June 23,1997 incorporated by reference to Exhibit 10.9 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
10.7		BWC Prospect Agreement, Dated April 1, 1998, incorporated by reference to Exhibit 10.14 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998.
10.8		Redfish Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.19 of Beta’s Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999.
10.9		Shark Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.20 of Beta’s Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999.
10.10		Northeast Hitchcock Agreement Dated July 30, 1999, incorporated by reference to Exhibit 10.24 of Beta’s Form 10-K/A for the year 1999 filed March 30, 2000.
10.11		Sarah White Agreement Dated July 30, 1999, incorporated by reference to Exhibit 10.25 of Beta’s Form 10-K/A for the year 1999 filed March 30, 2000.
10.12		Revised Joint Development Agreement dated August 8, 2000 between Red River Energy, L.L.C. and Avalon Exploration, Inc., incorporated by reference to Exhibit 10.27 of Beta’s Third Quarter Form 10-Q filed November 14, 2000.
10.13		Mushroom Project Participation Agreement, Austin and Waller Counties, Texas, dated June 14, 2000, incorporated by reference to Exhibit 10.29 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.

 

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10.14		Starboard Area Letter Agreement, Terrebone Parish, Louisiana dated June 16, 2000 incorporated by reference to Exhibit 10.30 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
10.15		First Amended and Restated Revolving Credit Agreement between Bank of Oklahoma and Red River Energy, LLC dated March 30, 1999, incorporated by reference to Exhibit 10.31 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
10.16		First Amendment to First Amended and Restated Revolving Credit Agreement between Bank of Oklahoma and Red River Energy, LLC dated February 1, 2000, incorporated by reference to Exhibit 10.32 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
10.17		Second Amendment to First Amended and Restated Revolving Credit Agreement between Bank of Oklahoma and Red River Energy, LLC dated June 15, 2000, incorporated by reference to Exhibit 10.33 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
10.18		Third Amendment to First Amended and Restated Revolving Credit Agreement between Bank of Oklahoma and Beta Oil & Gas, Inc. dated March 19, 2001, incorporated by reference to Exhibit 10.34 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
10.19		Form of Placement Agent Agreement for Preferred Placement Offering dated March 15, 2001, incorporated by reference to Exhibit 10.35 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
10.20		Letter Agreement Between Avalon Exploration, Inc. and Beta Oil & Gas, Inc. dated September 7, 2001 amending Revised Joint Development Agreement dated August 8, 2000 between Red River Energy, L.L.C. and Avalon Exploration, Inc., incorporated by reference to Exhibit 10.27 of Beta’s Third Quarter Form 10-Q filed November 14, 2000.
10.21		The Amended 1999 Incentive and Nonstatutory Stock Option Plan, incorporated by reference to Exhibit 99 of Beta’s 14A Definitive Proxy Statement dated and filed August 14, 2000.
10.22		Fourth Amendment to First Amended and Restated Revolving Credit Agreement dated March 15, 2002 between Beta Oil & Gas, Inc. and Bank of Oklahoma, N.A., incorporated by reference to Exhibit 10.36 of Beta’s Second Quarter 2002 Form 10-Q filed August 14, 2002.
10.23		Promissory Note dated March 15, 2002 between Beta Oil & Gas, Inc. and Bank of Oklahoma, N.A., incorporated by reference to Exhibit 10.37 of Beta’s Second Quarter 2002 Form 10-Q filed August 14, 2002.
10.24		Revolving Credit Note dated March 15, 2002 between Beta Oil & Gas, Inc. and Bank of Oklahoma N.A., incorporated by reference to Exhibit 10.38 of Beta’s Second Quarter 2002 Form 10-Q filed August 14, 2002.
10.25		Agreement between Beta Oil & Gas, Inc., Penn Virginia Oil & Gas Corporation, et.al. dated September 3, 2002, incorporated by reference to Exhibit 10.38 of Beta’s Third Quarter 2002 Form 10-Q filed November 14, 2002.
10.26		Letter Agreement between Beta Oil & Gas, Inc. and David A. Wilkins dated September 16, 2002 regarding the terms of his employment.
10.27		Separation Agreement with between Steve Antry and Beta Oil & Gas, Inc.dated October 1, 2002.
10.28		Employment Inducement Stock Option Agreement between Beta Oil & Gas, Inc. and David A. Wilkins dated October 1, 2002.
10.29		Fifth Amendment to First Amended and Restated Revolving Credit Agreement dated June 30, 2003 between Beta Oil & Gas, Inc. and Bank of Oklahoma, N.A., incorporated by reference to Exhibit 10.42 of Beta’s Second Quarter 2003 Form 10-Q filed August 13, 2003.
10.30		Promissory Note dated June 30, 2003 between Beta Oil & Gas, Inc. and Bank of Oklahoma, N.A., incorporated by reference to Exhibit 10.43 of Beta’s Second Quarter 2003 Form 10-Q filed August 13,2003.
10.31		Second Amendment to Second Amended and Supplemental Mortgage, Deed of Trust, Security Agreement, Financing Statement and Assignment dated June 30, 2003 from Beta Operating Company, L.L.C. to Michael M. Coats, Trustee and Bank of Oklahoma, N.A., incorporated by reference to Exhibit 10.44 of Beta’s Second Quarter 2003 Form 10-Q filed August 13,2003.
10.32		Amendment One to Amended and Restated 1999 Incentive and Nonstatutory Stock Option Plan, incorporated by reference to Exhibit 10.45 of Beta’s Second Quarter 2003 Form 10-Q filed August 13,2003.
10.33		Agreement among Beta Oil & Gas, Inc., Steve A. Antry, Rolf N. Hufnagel, Robert E. Davis, Jr., Robert C. Stone, Jr. and David A. Wilkins, dated June 20, 2003, regarding voting of shares at 2003 annual meeting incorporated by reference to Exhibit 10.1 of Beta's Form 8-K filed on June 24, 2004.
10.34		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, incorporated by reference to Exhibit 10.46 of Beta’s Third Quarter 2003 Form 10-Q filed November 14,2003.
10.35		Letter agreement dated July 9, 2003, between Beta Oil & Gas, Inc. and Petro Capital Advisors, L.L.C. relating to financial advisory services, incorporated by reference to Exhibit 10.47 of Beta’s Third Quarter 2003 Form 10-Q filed November 14, 2003.
10.36		Letter agreement dated October 13, 2003 between Beta Oil & Gas, Inc. and Petro Capital Advisors, LLC

 

40

 

		amending certain terms under the July 9, 2003 letter agreement, incorporated by reference to Exhibit 10.48 of Beta’s Third Quarter 2003 Form 10-Q filed November 14, 2003.
10.37		Securities Purchase Agreement dated December 12, 2003 between Beta Oil & Gas, Inc. and Petrohawk Energy, LLC, incorporated by reference to Appendix A to Beta's Preliminary Proxy Statement filed on Schedule 14A on January 9, 2004.
10.38		Stockholders Agreement by and among Beta Oil & Gas, Inc. and certain of its stockholders, incorporated by reference to Appendix E to Beta's Preliminary Proxy Statement on Schedule 14A on January 9, 2004.
16.1		Letter of HEIN & Associates LLP is incorporated by reference to Exhibit 16 Beta’s Current Report on Form 8-K/A filed on May 19, 2003.
21.1		List of Subsidiaries incorporated by reference to Exhibit 21 of Beta’s Form 10-K for the year 2000 filed April 2, 2001.
23.1		Consent of Hein & Associates, LLP. dated March 22, 2004
23.2		Consent of Ryder Scott Company, L.P. dated March 23 2004
23.3		Consent of Ernst & Young LLP dated March 25, 2004
23.4		Consent of Netherland, Sewell & Associates, Inc.dated March 23, 2004
31.1		Certificate of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certificate of Chief Financial Officer under Section 302 of Sarbanes-Oxley Act of 2002
32.1		Certificate of Chief Executive Officer and Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002

 

(b)  Beta did not file any current reports on Form 8-K during the fourth quarter of 2003.

 

41

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

	BETA OIL & GAS, INC.
Date: March 25, 2004	By:	/s/ David A. Wilkins
	David A. Wilkins
	Chief Executive Officer and President
	By:	/s/ Joseph L. Burnett
	Joseph L. Burnett
	Chief Financial Officer, and
	Principal Accounting Officer

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature			Title		Date
/s/ Robert E. Davis, Jr			Chairman of the		March 25, 2004
Robert E. Davis, Jr.			Board of Directors
/s/ David A. Wilkins			Chief Executive Officer		March 25, 2004
David A. Wilkins			and President
/s/ Joseph L. Burnett			Chief Financial Officer, Corporate		March 25, 2004
Joseph L. Burnett			Secretary and Principal Accounting Officer
/s/ David A. Melman			Director		March 25, 2004
David A. Melman
/s/ Rolf N. Hufnagel			Director		March 25, 2004
Rolf N. Hufnagel
/s/ Robert C. Stone, Jr.			Director		March 25, 2004
Robert C. Stone, Jr.

 

42

 

INDEX TO FINANCIAL STATEMENTS

 

 

Independent Auditors' Reports
Consolidated Balance Sheets - December 31, 2003 and 2002
Consolidated Statements of Operations - For the Years Ended December 31, 2003, 2002 and 2001
Consolidated Statement of Stockholders’ Equity - For the Years Ended December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows - For the Years Ended December 31, 2003, 2002 and 2001
Notes to Consolidated Financial Statements

 

F-1

 

REPORT OF INDEPENDENT AUDITORS

 

 

To the Board of Directors and Stockholders

  of Beta Oil & Gas, Inc.

 

We have audited the accompanying consolidated balance sheet of Beta Oil & Gas, Inc. as of December 31, 2003, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Beta Oil & Gas, Inc. at December 31, 2003, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States.

 

As discussed in Notes 1 and 5 to the consolidated financial statements, effective January 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations.  In addition, as also discussed in Note 1, effective January 1, 2003, the Company adopted, prospectively, the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation.

 

 

 

	ERNST & YOUNG LLP
Tulsa, Oklahoma
March 19, 2004

 

F-2

 

INDEPENDENT AUDITOR’S REPORT

 

 

The Stockholders and Board of Directors

Beta Oil & Gas, Inc.

Tulsa, Oklahoma

 

We have audited the consolidated balance sheets of Beta Oil & Gas, Inc. and subsidiaries as of December 31, 2002, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2002.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

 

We conducted our audits in accordance with auditing standards generally accepted in the United States of America.  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Beta Oil & Gas, Inc. and subsidiaries as of December 31, 2002 and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

 

 

/s/HEIN & ASSOCIATES LLP
HEIN & ASSOCIATES LLP
Certified Public Accountants
Orange, California
February 14, 2003

 

F-3

 

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

		DECEMBER 31,
		2003			2002
CURRENT ASSETS:
Cash		$	2,109,681		$	927,313
Accounts receivable
Oil and gas sales		1,898,746			1,676,935
Other		113,529			149,243
Income tax receivable		5,934			52,115
Prepaid expenses and other		266,728			187,818
Total current assets		4,394,618			2,993,424
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties		78,717,380			70,907,441
Unevaluated properties		1,294,212			4,582,605
Less – accumulated amortization and impairment of full cost pool		(39,740,116		)	(35,133,445		)
Net oil and gas properties		40,271,476			40,356,601
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system		1,496,404			1,507,177
Support equipment		197,379			221,413
Other		276,498			215,302
Less – accumulated depreciation		(813,450		)	(616,865		)
Net other operating property and equipment		1,156,831			1,327,027
OTHER ASSETS		292,318			76,208
TOTAL ASSETS		$	46,115,243		$	44,753,260
CURRENT LIABILITIES:
Notes payable		$	67,570		$	70,831
Accounts payable, trade		1,578,989			1,909,226
Futures transaction hedge liability		—			702,417
Dividends payable		112,707			112,707
Asset retirement obligation – current portion		171,860			—
Other accrued liabilities		566,990			275,290
Total current liabilities		2,498,116			3,070,471
LONG-TERM DEBT, less current portion		13,284,652			13,634,652
ASSET RETIREMENT OBLIGATION		1,062,860			—
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS’ EQUITY
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,271 shares issued and outstanding at December 31, 2003 and 2002; liquidation value at December 31, 2003 and 2002 is $5,702,097.		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 December 31, 2003 and 2002, respectively		12,447			12,447
Additional paid-in capital		51,924,225			51,917,235
Treasury stock, at cost; 16,765 and 6,015 shares reacquired at December 31, 2003 and December 31, 2002, respectively		(36,428		)	(28,153		)
Accumulated other comprehensive income		—			(702,417		)
Accumulated deficit		(22,631,233		)	(23,151,579		)
Total stockholders’ equity		29,269,615			28,048,137
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	46,115,243		$	44,753,260

 

See accompanying notes to consolidated financial statements.

 

F-4

 

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		FOR THE YEARS ENDED DECEMBER 31,
		2003			2002			2001
REVENUES:
Oil and gas sales		$	12,276,495		$	9,244,530		$	12,788,115
Field services		648,194			403,311			868,406
Total revenue		12,924,689			9,647,841			13,656,521
COSTS AND EXPENSES:
Lease operating expense		3,173,985			3,304,921			3,469,194
Field services		185,254			195,430			339,329
General and administrative		3,082,605			2,209,887			2,679,121
Full cost ceiling impairment		129,279			5,163,689			13,805,035
Depreciation and amortization expense		4,857,597			5,120,572			5,176,897
Total costs and expenses		11,428,720			15,994,499			25,469,576
INCOME (LOSS) FROM OPERATIONS		1,495,969			(6,346,658		)	(11,813,055		)
OTHER INCOME (EXPENSE):
Interest expense		(476,078		)	(558,297		)	(867,835		)
Interest income and other		(30,034		)	23,343			130,374
Total other expense		(506,112		)	(534,954		)	(737,461		)
INCOME (LOSS) BEFORE TAX PROVISION		989,857			(6,881,612		)	(12,550,516		)
INCOME TAX BENEFIT (PROVISION)		(24,000		)	—			3,504,432
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE		965,857			(6,881,612		)	(9,046,084		)
CUMULATIVE EFFECT ON PRIOR YEARS FROM ADOPTION OF FASB STATEMENT NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATION		1,640			—			—
NET INCOME (LOSS)		967,497			(6,881,612		)	(9,046,084		)
PREFERRED DIVIDENDS		(447,151		)	(447,151		)	(231,821		)
NET INCOME (LOSS) APPLICABLE TO COMMON SHAREHOLDER		$	520,346		$	(7,328,763	)	$	(9,277,905	)
BASIC NET INCOME (LOSS) PER COMMON SHARE		$	.04		$	(.59	)	$	(.75	)
DILUTED NET INCOME (LOSS) PER COMMON SHARE		$	.04		$	(.59	)	$	(.75	)
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		$	967,497		$	(6,881,612	)	$	(9,046,084	)
OTHER COMPREHENSIVE INCOME:
Transition adjustment related to change in accounting for derivative instruments and hedging activities (net of income taxes)		—			—			(953,488		)
Reclassification of realized loss on qualifying cash flow hedges (net of income taxes)		1,336,844			829,248			340,048
Unrealized gain (loss) on qualifying cash flow hedges (net of income taxes)		(634,427		)	(1,600,173		)	681,948
TOTAL COMPREHENSIVE INCOME (LOSS)		$	1,669,914		$	(7,652,537	)	$	(8,977,576	)

 

See accompanying notes to consolidated financial statements.

 

F-5

 

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002, AND 2001

 

 

												ADDITIONAL PAID IN CAPITAL						ACCUMULATED COMPREHENSIVE INCOME			ACCUMULATED DEFICIT			TOTAL STOCKHOLDERS’ EQUITY
		PREFERRED					COMMON								TREASURY STOCK
		SHARES		AMOUNT			SHARES		AMOUNT
BALANCES, January 1, 2001		—		$	—		12,340,951		$	12,341		$	46,592,976		$	—		$	—		$	(6,544,911	)	$	40,060,406
Issuance of shares pursuant to private placement, net		604,271		604			—		—			5,040,924			—			—			—			5,041,528
Issuance of shares for warrant exercise		—		—			57,621		58			180,799			—			—			—			180,857
Treasury stock acquired		—		—			—		—			—			(198,920		)	—			—			(198,920		)
Preferred dividends		—		—			—		—			—			—			—			(231,821		)	(231,821		)
Transition adjustment related to change in accounting for derivative instruments and hedging activities (net of income taxes)		—		—			—		—			—			—			(953,488		)	—			(953,488		)
Reclassification of realized (gain) loss on qualifying cash flow hedges (net of income taxes)		—		—			—		—			—			—			340,048			—			340,048
Unrealized gain (loss) on qualifying cash flow hedges (net of income taxes)		—		—			—		—			—			—			681,948			—			681,948
Net loss		—		—			—		—			—			—			—			(9,046,084		)	(9,046,084		)
BALANCES, Dec. 31, 2001		604,271		604			12,398,572		12,399			51,814,699			(198,920		)	68,508			(15,822,816		)	35,874,474
Issuance of shares for warrant exercise		—		—			47,500		48			94,952			—			—			—			95,000
Compensation associated with warrant extension		—		—			—		—			14,842			—			—			—			14,842
Treasury stock issued		—		—			—		—			—			170,767			—			—			170,767
Offering costs pursuant to 2001 private placement		—		—			—		—			(7,258		)	—			—			—			(7,258		)
Preferred dividends		—		—			—		—			—			—			—			(447,151		)	(447,151		)
Reclassification of realized (gain) loss on qualifying cash flow hedges		—		—			—		—			—			—			829,248			—			829,248
Unrealized gain (loss) on qualifying cash flow hedges		—		—			—		—			—			—			(1,600,173		)	—			(1,600,173		)
Net loss		—		—			—		—			—			—			—			(6,881,612		)	(6,881,612		)
BALANCES, December 31, 2002		604,271		$	604		12,446,072		$	12,447		$	51,917,235		(28,153		)	$	(702,417	)	$	(23,151,579	)	$	28,048,137
Compensation associated with issuance of options		—		—			—		—			251,972			—			—			—			251,972
Treasury stock acquired		—		—			—		—			—			(8,275		)	—			—			(8,275		)
Deferred offering costs relative to Petrohawk transaction		—		—			—		—			(244,982		)	—			—			—			(244,982		)
Preferred dividends		—		—			—		—			—			—			—			(447,151		)	(447,151		)
Reclassification of realized (gain) loss on qualifying cash flow hedges		—		—			—		—			—			—			1,336,844			—			1,336,844
Unrealized gain (loss) on qualifying cash flow hedges		—		—			—		—			—			—			(634,427		)	—			(634,427		)
Net income																					967,497			967,497
BALANCES, December 31, 2003		604,271		$	604		12,446,072		$	12,447		$	51,924,225		$	(36,428	)	$	—		$	(22,631,233	)	$	29,269,615

 

See accompanying notes to consolidated financial statements

 

F-6