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)

 

 

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes   ý No   o

 

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

 

The aggregate market value of such common stock held by non-affiliates was approximately $20,537,158 based on the reported closing sales price of $2.20 on the Nasdaq Market on June 28, 2002.

 

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 14, 2003, 12,446,072 shares of the registrant’s common stock were outstanding.

 

Certain sections of the registrant’s annual proxy statement for the 2003 annual meeting of stockholders on or about June 20, 2003 is incorporated by reference into Part III.

 

Exhibit table is on page 42.

 

 

TABLE OF CONTENTS

 

PART I
Glossary of Terms
Disclosure Regarding Forward-Looking Statements
Risk Factors
ITEM 1.	Business Of Beta
ITEM 2.	Properties Of Beta
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
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
PART III
ITEM 10.	Directors, Executive Officers, Promoters And Control Persons; Compliance With Section 16(A) Of The Exchange Act
ITEM 11.	Executive Compensation
ITEM 12.	Security Ownership Of Certain Beneficial Owners And Management
ITEM 13.	Certain Relationships And Related Transactions
ITEM 14.	Controls and Procedures
PART IV
ITEM 15.	Exhibits, Financial Statement Schedules And Reports On Form 8-K
Signatures
Exhibits

 

1

 

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 acquisitions 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.

 

“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.

 

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

 

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

 

“Net” oil and gas wells or “net” acres are determined by multiplying “gross” wells or acres by Beta’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 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.

 

“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 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

 

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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

 

We can give no assurance that our expectations and assumptions will prove to be correct.  Reserve estimates of oil and gas properties are generally different from the quantities of oil and natural gas that are ultimately recovered or found. This is particularly true for estimates applied to exploratory prospects and new production.  Additionally, any 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

 

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.

 

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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.

 

At December 31, 2002, we owned interests in approximately 307 gross wells, 177 net wells, in the Mid-Continent, Texas and Louisiana regions and participated in the drilling and completion of 21 gross wells (3.87 net wells) during the year.  Additionally, we own interests in 68,503 net acres in Kansas, Louisiana, Oklahoma, Offshore State and Federal Waters and Texas plus a minority interest in a West Queensland, Australia concession.

 

At December 31, 2002 our oil and gas properties had net proved reserves of 18.3 Bcfe, comprised of 14.7Bcf of natural gas and 608.6 MBbl of oil.  Average net daily production for 2002 was 8.2 MMcfe, down 6% from 2001 levels.  At year end 2002, the average net daily production was approximately 7.5MMcfe, compared to 9.5 MMcfe from year end 2001 levels, down 21 %.

 

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.

 

We have a limited operating history and developed property interests and have incurred operating losses since inception.

 

We were incorporated in June, 1997.  We have a limited operating history and are subject to the associated risks.  Since our inception, we have incurred operating losses every year except for 2000.  As of December 31, 2002, we had an accumulated deficit of $23.151 million.  If we are unable to generate positive cash flow from our oil and gas operations, we may continue to incur losses.  Our ability to achieve and maintain profitability is uncertain.

 

We are reliant on the skill, ability and decisions of third party operators to a significant extent.

 

We operate 44% of the producing wells in which we own a working interest and we are a non-operating working interest owner in the remaining 56%.  With respect to the latter, we have entered into joint operating agreements with third party operators for the conduct and supervision of drilling, completion and production operations of those wells and for the operation of those properties.  The success of the drilling, development and production of the oil and gas properties in which we have a non-operating working interest is substantially dependent upon the decisions of such third-party operators and their diligence to comply with various laws, rules and regulations affecting such properties.  The failure of any third-party operator to

 

•              make decisions,

•              perform their services,

•              discharge their obligations,

•              deal with regulatory agencies, and

•                                          comply with laws, rules and regulations affecting the properties in which we have an interest, including environmental laws and regulations

 

in a proper manner could result in material adverse consequences to our interest in any affected properties, including substantial penalties and compliance costs.  Such adverse consequences could result in substantial liabilities to us, which could negatively affect our results of operations.

 

We have not and do not anticipate paying any dividends on our common stock in the foreseeable future.

 

We have never paid any cash dividends on our common stock.  We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock.  Holders of our preferred stock are entitled to receive

 

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cumulative dividends at the annual rate of $.74 per share when and as declared by our board of directors.  No dividends may be paid on our common stock unless all cumulative dividends due on the preferred stock have been declared and paid.  We may also enter into credit agreements or other borrowing arrangements which may restrict our ability to declare dividends on our common stock.

 

Various factors, including fluctuations in oil and gas prices, economic conditions, environmental and other regulations, could have a material adverse effect on our financial condition and results of operations and may cause considerable volatility in the market price of our common stock.

 

The market value of our common stock may vary significantly in response to changes in our quarterly results of operations.  We expect to experience substantial fluctuations in oil and gas prices due to changes in the supply of and demand for oil and gas, which may be caused by

 

•              weather conditions,

•               political conditions in the Middle East and other regions,

•               domestic and foreign reserves and supply of oil and gas,

•               the price and availability of alternative fuels,

•               the level of consumer demand, or

•               general economic and market conditions.

 

In addition, our revenues will be affected by the success or failure of the efforts to drill exploratory wells in the unproven prospects in which we have an interest, the availability of a ready market for the oil and gas production from the wells in which we have an interest and the proximity of such well sites to pipelines and production facilities.  Drilling, completion and other costs and expenses will be affected by various market factors over which neither we nor our third party operators may have any control. Due to the uncertainty of our revenues, expenses and profits or losses, the market price of our stock may be volatile in the future.

 

Our future capital expenditures could exceed those amounts budgeted and could exceed our future funds available for those expenditures.

 

We project our 2003 capital expenditures to be approximately $3 million and expect our cash flow from operations and funds received from internally-generated prospects to fund those expenditures.  Our planned capital expenditures and/or administrative expenses could exceed those amounts budgeted and could exceed the available cash sourced for those expenditures.  While our projected cash expenditures may be as projected, cash flow from operations could be unfavorably impacted by lower than projected natural gas and crude oil prices and/or lower than projected production rates.  Additionally, lower natural gas and crude oil prices could adversely impact our ability to raise any funds from the sale of prospects. To the extent that the funds available from operations and prospect sales are insufficient to fund our activity, it may be necessary to raise additional funds through equity or debt financing.  Any equity financing could result in dilution to our then-existing shareholders.  Sources of debt financing may result in higher interest expense, further security interests in our assets, other equity interest to our lenders and similar developments.  Any financing, if available, may be on terms unfavorable to us.  If adequate funds are not obtained, we may be required to reduce or curtail operations.  We anticipate that our existing capital resources will be adequate to satisfy our operating expenses and capital requirements for 2003.

 

Our hedging activities could result in losses.

 

We have previously engaged in oil and gas hedging activities and intend to continue to consider various hedging arrangements to realize commodity prices which we consider protective or favorable.  See Item 7A.  Quantitative and Qualitative Disclosure About Market Risk for a discussion of our current hedging activity.  As with the natural gas contracts, the crude oil contracts are costless and no net premium is received in cash or as a favorable rate.  The impact of changes in the market price for oil and gas on the average oil and gas prices received by us may be reduced from time to time based on the level of our hedging activities.  These hedging arrangements may limit our potential gain if the market prices for oil and gas were to rise substantially over the ceiling price established by the hedge.  In addition, our hedging arrangements expose us to the risk of financial loss in certain circumstances, including instances in which (1) production is less than expected or (2) the counterparties to our hedging arrangements fail to honor their financial commitments.

 

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We have substantial long-term indebtedness.

 

Under our current credit facility, which was acquired through the Red River Energy merger, we have a total indebtedness outstanding of approximately $13.7 million with a current total borrowing capacity of  $14.5 million.  With a reduction in commodity prices and a reduction in our proved developed reserves, our borrowing capacity has not significantly increased and is not a material source of funds.  We are currently required to pay interest only on the amount outstanding on a monthly basis.  Should our proved developed reserves not materially increase and/or pricing substantially decrease before the next re-determination date, our current borrowing base may be reduced below the amount currently borrowed and outstanding.  If this event occurs we would be obligated to pay down the outstanding amount to the re-determined borrowing capacity.  We would rely on cash flow from operations and funds generated from prospect sales to make this pay down.  Since the facility is secured by our producing oil and gas properties, should we be unable to pay down the obligation at re-determination or maturity, we could sustain a loss on our investment as a result of foreclosure by the lender on the interests in these properties. The next re-determination date is April 2003 and the credit facility matures in March 2004.

 

Our oil and gas activities are subject to various risks which are beyond our control.

 

Our operations are subject to many risks and hazards incident to exploring and drilling for, producing, transporting, marketing and selling oil and gas.  Although we or the third party operator of the properties in which we have an interest may take precautionary measures, many of these risks and hazards are beyond our control and unavoidable under the circumstances.  Many of these risks or hazards could materially and adversely affect our revenues and expenses, production of oil and gas in commercial quantities, the rate of production and the economics of the development of, and our investment in the prospects in which we have or will acquire an interest.  Any of these risks and hazards could materially and adversely affect our financial condition, results of operations and cash flows.  Such risks and hazards include:

 

•                                          human error, accidents, labor force and force majeure factors that may cause personal injuries or death to persons and destruction or damage to equipment and facilities,

•                                            blowouts, fires, pollution and equipment failures that may result in damage to or destruction of wells, producing formations, production facilities and equipment,

•               unavailability of materials and equipment,

•               engineering and construction delays,

•               unanticipated transportation costs and delays,

•                                            unfavorable weather conditions, hazards resulting from unusual or unexpected geological or environmental conditions,

•               environmental regulations and requirements,

•                                            accidental leakage of toxic or hazardous materials, such as petroleum liquids or drilling fluids into the environment,

•                                            changes in laws and regulations, including laws and regulations applicable to oil and gas activities or markets for the oil and gas produced,

•                                            fluctuations in supply and demand for oil and gas causing variations within the prices we receive for our oil and gas production,

•                                            the internal and political decisions of OPEC and oil and gas producing nations and their impact upon oil and gas prices.

 

As a result of these risks, expenditures, quantities and rates of production, revenues and cash operating costs may be affected materially and adversely and may differ materially from those anticipated by us.

 

We depend substantially on the continued presence of key personnel for critical management decisions and industry contacts.

 

Our future performance will be substantially dependent on the performance of our executive officers and key employees.  The loss of the services of any of our executive officers or other key employees for any reason could have a material adverse effect on our business, operating results, financial condition and cash flows.

 

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Governmental and environmental regulations could adversely affect our business.

 

Our business is subject to federal, state and local laws and regulations on taxation, the exploration for and development, production and marketing of oil and gas and safety matters.  Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, prevention of waste, unitization and pooling of properties and other matters.  These laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning our oil and gas wells and other facilities.  In addition, these laws and regulations, and any others that are passed by the jurisdictions where we have production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit our revenues.

 

Our operations are also subject to complex environmental laws and regulations adopted by the various jurisdictions in which we have oil and gas operations.  We could incur liability to governments or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water, including responsibility for remedial costs.  We could potentially discharge these materials into the environment in any of the following ways:

 

•                                          from a well or drilling equipment at a drill site;

•                                            from gathering systems, pipelines, transportation facilities and storage tanks;

•                                            damage to oil and natural gas wells resulting from accidents during normal operations; and

•                                            blowouts, cratering and explosions.

 

Because the requirements imposed by laws and regulations are frequently changed, we cannot assure you that laws and regulations enacted in the future, including changes to existing laws and regulations, will not adversely affect our business.  In addition, because we acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage caused by the former operators.

 

Competition.

 

The oil and gas industry is highly competitive in many respects, including identification of attractive oil and gas properties for acquisition, drilling and development, securing financing for such activities and obtaining the necessary equipment and personnel to conduct such operations and activities.  In seeking suitable opportunities, we compete with a number of other companies, including large oil and gas companies and other independent operators with greater financial resources and, in some cases, with more expertise.  Many other oil and gas companies in the industry have financial resources, personnel and facilities substantially greater than ours and there can be no assurance that we will be able to compete effectively with these larger entities.

 

Development Risks and Production.

 

A portion of our oil and gas reserves is or may become, with future successful drilling of our prospects, proved undeveloped reserves.  Successful development and production of such reserves, although categorized as “proved”, cannot be assured.  Additional drilling will be necessary in future years both to maintain production levels and to define the extent and recoverability of existing proved undeveloped reserves.  There is no assurance that our present oil and gas wells will continue to produce at current or anticipated rates of production, that development drilling will be successful, that production of oil and gas will commence when expected, that there will be favorable markets for oil and gas which may be produced in the future or that production rates achieved in early periods can be maintained.

 

Title to the properties in which we have an interest may be impaired by title defects.

 

We generally obtain title opinions on properties which we drill or acquire.  However, there is no assurance that we will not suffer a monetary loss from title defects or failure.  Under the terms of the operating agreements affecting our will not suffer any monetary loss arising from title failure or defects.  Under the terms of the operating agreements affecting its properties, any monetary loss is to be borne by all parties to any such agreement in proportion to their interests in such property.  If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

 

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We cannot be certain that the insurance coverage maintained by us will be adequate to cover all losses which may be sustained in connection with all oil and gas activities.

 

We have purchased and are maintaining a general and excess liability policy with a total limit on claims of $26,000,000 and a workers compensation policy to provide added insurance if the coverage provided by an operators policy is inadequate to cover our losses.  Our policies, and the policies maintained by our third party operators, which have limits ranging from $10,000,000 to $25,000,000 depending on the type of occurrence, generally cover:

 

•                                          personal injury,

•                                            bodily injury,

•                                            third party property damage,

•                                            medical expenses,

•                                            legal defense costs,

•                                            pollution in some cases,

•                                            well blowouts in some cases and

•                                            workers compensation

 

A loss in connection with our oil and gas properties could have a materially adverse effect on our financial position and results of operation to the extent that the insurance coverage provided under our policies cover only a portion of any such loss.

 

Our international operations may be adversely affected by a number of factors.

 

Although the majority of our exploration efforts are focused in the United States, we have international operations in Eastern Australia.  Our operations in Eastern Australia represent our only foreign operations.  We currently have no binding agreements or commitments to make any material international investment.

 

Our foreign operations in Eastern Australia may be adversely affected by a number of factors, including:

 

•                                          local political and economic developments could restrict or increase the cost of our foreign operations;

•                                            exchange controls and currency fluctuations;

•                                            royalty and tax increases and retroactive tax claims could increase costs of our foreign operations;

•                                            expropriation of our property could result in loss of revenue, property and equipment;

•                                            import and export regulations and other foreign laws or policies could result in loss of revenues; and

•                                            laws and policies of the United States affecting foreign trade, taxation and investment could restrict our ability to fund foreign operations or make foreign operations more costly.

 

Our future performance depends upon our ability to find or acquire additional oil and gas reserves that are economically recoverable.

 

In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics.  Unless we successfully replace the reserves that we produce, our reserves will decline, resulting eventually in a decrease in oil and gas production and lower revenues and cash flow from operations.  We intend to increase our reserves after taking production into account through exploitation, development and exploration on our existing oil and gas properties as well as on newly acquired properties.  We may not be able to replace reserves from such activities at acceptable costs.  Low prices of oil and gas may further limit the kinds of reserves that can economically be developed.  Lower prices also decrease our cash flow and may cause us to decrease capital expenditures.

 

We are continually identifying and evaluating opportunities to acquire oil and gas properties, including acquisitions that would be significantly larger than those consummated to date by us.  We cannot assure you that we will successfully consummate any acquisition, that we will be able to acquire producing oil and gas properties that contain economically recoverable reserves or that any acquisition will be profitably integrated into our operations.

 

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Estimating reserves and future net reserves involves uncertainties and oil and gas price declines may lead to impairment of oil and gas assets.

 

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer.  The reserve data included in the documents incorporated herein by reference represent only estimates.  In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct over time.

 

Quantities of proved reserves are estimated on economic conditions in existence in the period of assessment.  Lower oil and gas prices may have the impact of shortening the economic lives on certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, thus reducing proved property reserve estimates.  If such revisions in the estimated quantities of proved reserves occur, it will have the effect of increasing the rates of depreciation, depletion and amortization expense.  The revisions may also be sufficient to trigger impairment losses on certain properties which would result in a further non-cash charge to earnings.

 

If we miscalculated our future cash requirements due to any of the risk factors detailed here or for any other reason, we would then need to service our existing bank debt and/or fund our growth strategy though additional financings and failure to obtain such financings would not only hamper our ability to expand our oil and gas operations but could result in a contraction of our business and activities.

 

Failure to raise such additional funds could materially adversely affect:

 

•                                          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.

 

Without the availability of additional funds, we may be required to:

 

•                                                                       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.

 

If additional financing is obtained by us, such financing:

 

•                                          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 opportunities.  The decision was made to bring in new management in order to build the technical capabilities of the 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 he immediately began reviewing the existing assets of the company.  The new mission statement for our company is to exercise an investment discipline in oil and gas projects while methodically building value for our shareholders.

 

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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 will allow us to centralize and better coordinate the operating, engineering and G&G functions.  As part of the new technical focus for the company, we are in the process of hiring new engineering and G&G personnel for the Tulsa office.

 

Our main goal is to maximize Beta’s 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 for 2003 is to shift our efforts from the high-risk exploration projects in South Texas to lower-risk Mid-Continent exploitation projects.  Our largest asset is the West Edmond Hunton Lime Unit (WEHLU) located primarily in Oklahoma County, Oklahoma, in which we have approximately 98% ownership in 30,000 acres.  We believe that this asset has infill development potential that we plan to pursue during 2003.  Accordingly, the largest portion of our 2003 capital budget will be expended on WEHLU.  We will further pursue new stimulation techniques for our coalbed methane production in Tulsa County, OK as well as additional development drilling opportunities in our Hitchita Field in McIntosh County, OK.  We plan to participate in South Louisiana drilling prospects at West Broussard, Lake Boeuf and Lapeyrouse.  Due to the high drilling costs associated with the South Louisiana wells, our ownership position in these wells will be much lower than our Mid-Continent wells.  We will continue to evaluate all options with our South Texas holdings but with a much lower risk profile.  In addition, management 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 all of our 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,
		2002				2001				2000
		Gross		Net		Gross		Net		Gross		Net
Exploratory:
Productive (1)		5		0.62		19		4.40		14		2.24
Dry		5		0.83		12		2.71		5		1.13
Total Exploratory		10		1.45		31		7.11		19		3.37
Development:
Productive (1)		8		1.84		14		3.23		2		.26
Dry		3		0.58		4		0.63		—		—
Total Development		11		2.42		18		3.86		2		.26
Total:
Productive (1)		13		2.46		33		7.63		16		2.50
Dry		8		1.41		16		3.34		5		1.13
Total		21		3.87		49		10.97		21		3.63

 

(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.

 

Subsequent to December 31, 2002, drilling commenced on one gross (.05 net) exploratory well which  is 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, 2002.  We have not included in the table acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests. Shut-in wells currently not capable of production are not included in the producing well information.

 

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		Producing Wells								Acreage
		Oil				Gas				Developed				Undeveloped
		Gross		Net (1)		Gross		Net (1)		Gross		Net (2)		Gross		Net
Texas		22		4.39		46		6.79		24,520.0		1,740.2		49,919.7		16,190.8
Oklahoma		29		15.30		87		56.34		54,986.3		42,341.9		2,695.5		1,710.1
Louisiana		1		0.12		9		0.79		8,111.2		920.6		4,251.6		1,482.3
Kansas		14		14.00		2		2.00		3,477.5		3,477.5		640.0		640.0
California		—		—		—		—		—		—		—		—
Wyoming		—		—		—		—		—		—
		66		33.81		144		65.92		91,095.0		48,480.2		57,506.8		20,023.2

 

(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 34,495.8 gross acres and 11,501.4 net acres of unevaluated leasehold will expire in 2003.

 

At December 31, 2002, we had proved reserves of 608.6 MBbls of oil and 14.7 Bcf of gas as estimated by Ryder Scott and Company, an independent engineering firm.  These reserves are located entirely within the United States.  The following table sets forth, at December 31, 2002, 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.

 

 

The above figures do not reflect the estimated future net revenues and the present value of future net revenues, discounted at an annual rate of 10%, for our McIntosh gathering system, which were $2,749,393 and $1,834,336, respectively.

 

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 average year-end prices for crude oil and natural gas were $29.53/Bbl and $4.84/Mcf at December 31, 2002. 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 13. Unaudited Supplementary Oil And Natural Gas Information.

 

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 2002.

 

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

 

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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 Supplemental Data, Note 2. Acquisitions, Sales And Oil And Gas Operations.

 

Capitalized costs of our evaluated and unevaluated properties at December 31, 2002, 2001 and 2000 are summarized as  follows:

 

 

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 Mcf equivalent 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 2002 average natural price was reduced by $.25 per Mcf and average crude oil price was reduced by $1.76 per Bbl due to our hedges.  In 2001, the impact of hedges reduced our average natural gas price by $0.25 per Mcf and increased our average crude oil price by $.76 per Bbl.

 

 

Our current areas of operations and holdings include Oklahoma, Louisiana, Kansas and  Texas.  The following discussion summarizes our present operations, acreage position,  results from 2002 and  future plans.

 

In September 2000, we acquired Red River Energy, Inc.  We issued 2,250,000 shares of its common stock valued at $14.355 million assuming a Beta common stock price of $6.38.  We acquired interests in over 230 wells, which included 145 operated wells in Oklahoma, Kansas and Texas.  The acquisition significantly increased our base production level and monthly cash flow from operations.  Please refer to Item 8. Financial Statements And Supplementary Data, Note 2. Acquisitions, Sales And Oil And Gas Operations.

 

In June 2000, prior to our acquisition, Red River Energy acquired interests in 124 properties and prospects in 26 fields located in Oklahoma, Kansas and Texas from ONEOK Resources Company.  The properties are geographically distributed into three areas: Mid-Continent (17 fields), West Texas (4 fields) and onshore Gulf Coast (5 fields).  The package included 34 gross (30 net) operated oil wells, 3 gross (2 net) operated gas wells, 30 gross (4 net) non-operated oil wells and 44 gross (7 net) non-operated gas wells.  In total, 74 gross wells are non-operated, or 67% of the total wells acquired.  The majority of the value is associated with the operated properties in the Mid-Continent region.

 

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Oklahoma

WEHLU

The West Edmond Hunton Lime Unit (WEHLU) is Beta’s largest holding, covering 30,000 acres (about 47 square miles) primarily in Oklahoma County, Oklahoma. The field has 55 oil and natural gas wells (22 currently producing) with stable production holding the entire unit. Beta holds a 98%WI and is the operator.  At December 31, 2002, WEHLU had proven reserves of approximately 10.9 Bcfe or approximately 59% of our total proven reserves.  WEHLU currently produces approximately 3.1 Mcfe per day or 40% of our current production.

 

The WEHLU Field, originally discovered in 1942, is the largest Hunton Lime Field in the state, representing nearly 40% of the state’s Hunton production. We have an agreement with Avalon Exploration, Inc. of Tulsa, Oklahoma to jointly test and develop additional production in WEHLU.   The agreement with Avalon covers 5,680 acres and is located in the Central-Northwest area of the field.

 

Avalon has drilled four wells in WEHLU under their agreement with Beta.  The first two wells were drilled to test the productivity of the lower Hunton (Chimney Hill) in the Western portion of the field.  Of these two wells, one well was recompleted in the Upper Hunton (Bois d’Arc) and the other well was plugged and abandoned. The final two wells were productive.  To date we have not elected to exercise our “look-back” right to participate in the four wells drilled by Avalon. A summary of the current production resulting from the Avalon drilling is listed below.

 

Well		Oil - Bbl per day		Gas - Mcf per day		Water - Bbl per day
Mable T		5		240		50
Damogram		15		280		160
Willey		60		280		200

 

Currently, we are negotiating with Avalon regarding the drilling of a water disposal well as production in the Avalon area is limited by water handling.  Subsequent to the addition of a water disposal well, Avalon plans on drilling two wells in 2003.  We anticipate participating at some level in the drilling of these wells.

 

In 2003 we have committed approximately $1.5 million of our capital budget for drilling and re-working in the WEHLU area.  The initial focus will be to reactivate some of the shut-in wells and to stimulate existing wells to optimize production.  Concurrent with those efforts, we expect to drill one well in the second half of 2003, outside of the Avalon area of mutual interest (AMI).

 

CHARLIE PROJECT

The Charlie Project is a coalbed methane property also acquired in the Red River Energy acquisition.  Charlie has current daily average production of 460 gross (359 net) Mcf from 21wells.  This property was given no value at the time of the acquisition because of limited early response of the coalbed wells and the  use of the property as collateral for a non-recourse note.  Since the acquisition, the note has been extinguished and production stimulation techniques applied to the existing wells.  In 2002, three wells were stimulated or reworked and an additional six wells have been identified for new fracturing stimulation in 2003.  At December 31, 2002, this project had approximately 272 MMcf of proved reserves.  We have a 100% working interest in the project.

 

McINTOSH COUNTY

We hold approximately 12,038 acres (10,267 net acres) of oil and gas leases and have interests in 56 gross wells (34 net wells).  We operate 43 of these wells in the N.E. Hitchita Field.  In 2002, we participated in the drilling of 2 gross wells (0.3 net wells), which were successful completions,  one in the Arbuckle formation and one in the Wilcox formation.  The current net daily production  from these wells is approximately 2,900 gross (700 net) Mcf of natural gas.

 

The gas produced is dry and is sold into a low-pressure gathering system of another wholly owned 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 2002, our gas gathering system in this area had gathering revenues of approximately $402,000.

 

Louisiana

Since 1999, we have invested approximately $13.9 million in leases, seismic data collection and drilling in South Louisiana.  Currently, we have production in the Lapeyrouse Field located in Terrebonne Parish as well as shallow offshore production in the West Cameron Blocks 39 and 49 located in Cameron Parish.  We have working interests in 10

 

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gross (.92 net) produding wells and 1 saltwater disposal well with a current net daily production of 1.4 MMcfe of natural gas.  Our working interest in the producing wells range from .02% to 16.7%.  We have leasehold positions in the West Broussard Field in Lafayette Parish,  the Lake Boeuf Field in LaFourche Parish and the Lapeyrouse Field in Terrebonne Parich.

 

LAPEYROUSE PROJECT

The Lapeyrouse Prospects are located in Terrebonne Parish, Louisiana where we have a leasehold position covering 2,632 gross acres (201 net acres).  Within this acreage position, we have one proven undeveloped location and 3 probable locations identified for future drilling.  During 2003, we plan to participate in the drilling of two   wells in Lapeyrouse with a 5-8% working interest.  The first well, the T.Cenac #1 was successfully completed in the first quarter of 2001.

 

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.   Drilling activities commenced in mid-January on the M. A. Failla #1 well on the East unit.  The well reached total depth at 15,718 feet on March 10, 2003.    Currently, the well is in the evaluation and testing phase.  We have a 4.8% working interest in this well, increasing to 10.1% working interest after payout.

 

Should the M.A. Failla # 1 be successful and support additional development of the West unit, we are in a position to own a larger interest in that unit.  A 3-D seismic survey is underway and should be completed during the second quarter of 2003 to help further delineate the potential of the area.

 

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 of the M.A. Failla #1 could support further revision of the classification of 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 13. Unaudited Supplemental Oil And Natural Gas Information.

 

LAKE BOEUF PROSPECT

In 2001, we acquired approximately 660 gross and net acres on a structural closure identified by 3-D seismic located in the Lake Boeuf Field, LaFourche Parish.  We have three drilling prospects identified within our leasehold that include a 15,200’ directional well, a 13,400’ directional well and a 13,300’ vertical well.  These three prospects could have significant upside potential.  Due to the exploratory nature of the prospects and the high drilling costs associated with these wells, we will either participate with a carried interest or a very small working interest (less than 10%).  The 15,200’ directional well will test various Rob L sands and was originally scheduled to spud during late 2002.  Due to delays on the part of our partners, this well has been postponed.  Given the current interest level in these prospects, we anticipate that one or more of these prospects will be drilled during 2003.

 

Texas

JACKSON COUNTY

Jackson County Texas has been the focal point of our exploration activities since we were founded in 1997.  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 has resulted in a total of 28 (3.89 net) discoveries out of 45 (7.07 net) wells drilled to date.  The successful wells were shallow-to-deep Frio and Yegua tests.  To date, we have not had 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 $19.5 million since inception on lease acquisition, seismic and drilling activity.  Currently, our average net daily production for  Jackson County  is approximately 1,583 Mcfe of natural gas, or 16% 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

 

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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 recorded an impairment charge in Jackson County at the end of 2002 totaling $4.9 million, or $.39 per diluted share.

 

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 1,301 gross (468 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.

 

Big Twelve Project - In 2001, we acquired a 12.5% interest in this project, which flanks our Mexican Sweetheart project to the north and our Texana project to the west, for $250,000.  A 19,000 Wilcox exploratory well was drilled in the last half of 2001.  The well did encounter Wilcox sands but was deemed  non-commercial.  However, it did prove up the Yegua formation and was successfully completed.  The well went on line in January 2002 and is currently producing 692 gross (64net) Mcf of natural gas per day and 37 gross (3 net) barrels of condensate per day. We currently have 6,088 gross (760 net) acres under lease.

 

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.  A well is currently drilling nearby that will assist in determining the prospect potential.

 

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.  Additional subsurface geology and seismic work is planned this year to better delineate the prospect.  We intend to sell down out interest in this prospect to industry partners and retain a carried and/or reversionary interest.

 

WALLER COUNTY

Brookshire Dome

The Brookshire Dome field is a salt dome field located approximately 30 miles west of Houston in Waller County, TX.  Beta acquired interests in existing production in the Brookshire Dome area in mid-2001.  To date, Beta has leased approximately 4,281 gross acres (1,086 net acres) for both exploration and exploitation opportunities.  Beta is not currently leasing any additional acreage at Brookshire.  Based on the success of a shallow Miocene play south of Beta’s acreage block, an intensive drilling program commenced in the second half of 2001 targeting similar shallow Miocene oil and gas sands, above the salt.  The potential also exists for deeper sub-salt Yegua and Wilcox objectives (Beta participated in a deeper test well in 2000 which was unsuccessful).  Revere Corporation and Johnson Sanford are the operators of the wells in which Beta has an interest.  Revere is currently very active in drilling the shallow Miocene targets and under the agreement in place, Beta has the option to either participate or farm out on a well-by-well basis.  During 2002, the company participated in the drilling of 12 gross wells (2.49 net wells), of which 9 gross wells (2.00 net wells) were successful.  Currently, the company has interest in 26 gross wells, 6.59net wells at Brookshire Dome.  The net amount expended to date in the Brookshire Dome area is $3.7 million.

 

GALVESTON COUNTY

The Greens Lake Project

The Rubel #1 (known as the Sara White Prospect), operated by Ocean Energy, was spud in the fourth quarter of 2001 and completed during the second quarter of 2002.  A production test was performed and the well flowed 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 re-completions up hole have also been unsuccessful.  Currently, the well is shut in and incapable of producing.  We are waiting on a recommendation from the operator as to future operations.  We have a 31% working interest in this well and our net expenditure to date is approximately $2.6 million.

 

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RED RIVER AND LAMAR COUNTIES

The Detroit Project

The Detroit Prospect is a large, NE-SW trending, seismically controlled feature in the Northwestern portion of Red River County and Eastern Lamar County, in Northeast Texas.  This prospect covers 9,401 gross (7,050 net) acres.  ..  The project was developed as a rework of existing seismic data and an extensive radiometric survey of the entire area for surface detection of hydrocarbons.  There is an industry partner who has a similar acreage position in the area and we are jointly looking for investor(s) to drill this prospect.  Due to the high-risk exploration profile of this prospect, we will retain a small working interest in the initial exploratory well.  The majority of the original leases was consummated in 2000 and has primary lease terms ranging from two to three years. .  Should drilling not commence in 2003, the remainder of the existing leases will expire in 2003.  To date, we have spent approximately $880,000 for acreage, seismic and other geological and geophysical costs.

 

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% or 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.

 

		2002		2001		2000
Duke Energy		31	%	29	%	19	%
Allegro Investments		14	%	16	%	12	%

 

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.

 

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.  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.

 

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

 

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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.  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.

 

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 15 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.

 

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PREMISES

We lease approximately 6,400 square feet in Tulsa, Oklahoma, which includes offices and storage space.  All of our corporate functions and some operational functions are conducted from this site.  The lease expires January 2004, and requires monthly payments of approximately $9,300 per month.  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

 

On November 29, 2000 in the District Court of Tulsa County, State of Oklahoma, a Petition was filed by ONEOK Energy Marketing and Trading Company, L.P. (“ONEOK”), plaintiffs, naming us and two of our wholly-owned subsidiaries, Red River Field Services, L.L.C. and Red River Energy, L.L.C., as defendants.  In the lawsuit, plaintiff alleges that we discontinued selling gas to plaintiff in breach of a fixed price agreement and sold the gas instead to other suppliers.  We counterclaimed on January 24, 2001, alleging that the contract had been terminated pursuant to its terms for nonpayment by plaintiff for gas supplied prior to termination, and seeking damages for the unpaid charges of $282,096.

 

In 2002, we settled the above claim and counterclaim with ONEOK through independent mediation.  It was mutually agreed to release all claims and we paid ONEOK $43,000 in addition to the $282,096 of funds held by ONEOK.  Each party was responsible for their legal fees and costs associated with this matter of which our total legal fees were approximately $85,600.  Net of amounts due from joint interest partners, a non-recurring charge of $205,415 was recorded to income in the year ended December 31, 2001 related to the settlement.  In the fourth quarter of 2002, we reserved approximately $155,000 relative to the amount due from the joint interest owners involved and accordingly charged bad debt expense for such amount.  We are currently negotiating with the joint owners for settlement of the amount due to us.

 

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, 2002.

 

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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 since inception.  For the foreseeable future, we intend to retain any funds otherwise available for dividends.

 

 

Approximately 211 shareholders of record and approximately 2,150 beneficial owners as of March 14, 2003 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,
		2002			2001			2000			1999			1998
Income Statement Data:
Operating revenues		$	9,647,841		$	13,656,521		$	8,357,867		$	1,199,480		$	—
Operating expense (1)		3,500,351			3,808,523			1,516,113			81,538			—
General and administrative		2,209,887			2,679,121			2,141,005			1,418,240			746,769
Impairment expense		5,163,689			13,805,035			—			1,224,962			1,670,691
Depreciation and depletionexpense		5,120,572			5,176,897			2,693,439			914,233			11,883
Interest expense		558,297			867,835			393,008			2,966,651			—
Net income (loss)		(6,881,612		)	(9,046,084		)	1,425,565			(5,384,403		)	(2,384,500		)
Earnings (loss) per share:
Basic		$	(.59	)	$	(.75	)	$	.13		$	(.66	)	$	(.37	)
Diluted		(.59		)	(.75		)	.13			(.66		)	(.37		)
Weighted average common shares and equivalent outstanding:
Basic		12,417,957			12,368,373			10,616,692			8,160,000			6,366,923
Diluted		12,417,957			12,368,373			11,281,413			8,160,000			6,366,923
Balance sheet data:
Working capital		$	(77,047	)	$	(103,550	)	$	3,533,237		$	2,034,268		$	(96,457	)
Total assets		44,753,260			52,629,378			58,466,152			20,881,475			13,618,471
Total long term debt		13,634,652			13,648,727			13,814,034			27,939			—
Stockholder’s equity		28,048,137			35,874,474			40,060,406			20,588,237			13,299,342
Proved Reserves
Oil (Mbbls)		608.6			836.8			814.0			13.2			1.4
Gas (MMcf)		14,688.2			24,710.0			19,418.0			4,170.0			1,596.7
Total (MMcfe)		18,320.0			29,730.8			24,302.8			4,249.2			1,605.1
Present value of estimate future net revenues before income tax discounted at 10%		$	35,929,439		$	31,295,012		$	100,199,288		$	6,012,972		$	1,716,608
Standardized measure		$	35,929,439		$	31,295,012		$	71,458,654		$	6,012,972		$	1,716,608

 

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

 

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SELECTED QUARTERLY  FINANCIAL DATA		For  the quarter ended
(In Thousands of Dollars)		March 31			June 30			September 30			December 31
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		)	(.46		)
Diluted		.07			.03			(.39		)	(.46		)
2000
Revenues		$	940.3		$	1,082.3		$	2,022.8		$	4,312.5
Revenues less operating expense		906.4			959.8			1,689.5			3,286.1
Net income (loss)		(125.4		)	(50.5		)	840.4			761.1
General and administrative expense		489.6			435.1			651.6			564.7
Earnings (loss) per share:
Basic		(0.01		)	(0.01		)	0.08			0.06
Diluted		(0.01		)	(0.01		)	0.07			0.06

 

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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, 2002 and 2001, and the results of operations for the years ended December 31, 2002, 2001 and 2000.

 

General

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

 

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,
		2002			2001			2000
Beginning cash balance		$	556,199		$	1,536,186		$	1,448,655
Sources of cash:
Cash provided by operations		2,977,752			9,047,095			3,229,081
Cash provided by financing activities		328,637			6,822,927			3,551,924
Cash provided by sales of oil & gas properties and Equipment		3,231,944			1,082,524			100,000
Cash provided from acquisition		—			—			895,097
Total sources of cash including cash on hand		7,094,532			18,488,732			9,224,757
Uses of cash:
Oil and gas expenditures, net of prepaid drillingadvances		(5,442,418		)	(15,653,461		)	(6,944,614		)
Other equipment		(36,103		)	(177,103		)	(92,203		)
Cash used by financing activities		(688,698		)	(2,101,969		)	(651,754		)
Total uses of cash		(6,167,219		)	(17,932,533		)	(7,688,571		)
Ending cash balance		$	927,313		$	556,199		$	1,536,186

 

Our working capital was a ($77,047) deficit at December 31, 2002 compared to a ($103,550) deficit at December 31, 2001 and a $3,533,237 surplus at December 31, 2000.    Even though our net working capital position and liquidity improved in 2002, several factors or events negatively impacted this improvement.  These factors were:

 

•    lower than anticipated production rates from our Gulf Coast and South Texas properties,

•             a significant cost overrun of approximately $1.0 million (net to our 31% working interest)  and limited production associated with the Rubel #1, Sara White prospect located in Galveston County, Texas,

•    higher operating expense associated with unplanned weather-related repairs on certain Mid-Continent properties and

•    no significant production additions from our exploration and development activity during the year.

 

At December 31, 2002, we had a futures transaction hedge liability, associated with that portion of our future production volume currently hedged, of ($702,417) compared to a futures derivative asset of $68,508 at December 31, 2001.  The futures transaction hedge asset (liability) represents the potential unrealized increase or decrease in our future oil and gas revenue based on the current outstanding derivative contracts.  The estimate is based on the NYMEX natural gas and

 

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crude oil futures prices in effect at December 31, 2002 and December 31, 2001 which may vary materially from month to month.

 

Total proved reserve volumes at December 31, 2002 were 14.7 Bcf of natural gas and 608.6 MBbl of oil, or 18.3 Bcfe of natural gas compared to December 31, 2001 proved reserves of 24.7 Bcf of natural gas and 836.8 MBbl of oil or 29.7 Bcfe of natural gas.  Total proved reserves decreased approximately 11.4 Bcfe, or 46%, from the prior year primarily due to the reclassification of the reserves associated with our West Broussard prospect from proved undeveloped (PUD) to non-proven and 2002 production of approximately 3.0 Bcfe of natural gas.

 

For the twelve months ended December 31, 2002, we expended approximately $5.4 million (net of prepaid drilling advances) primarily comprised of:

 

•    $1.1 million related to our Jackson County drilling, seismic and leasing activity,

•    $1.5 million expended on the Rubel #1, Sara White prospect located in Galveston County, Texas,

•             $1.2 million for the drilling, completion and land activity associated with our Brookshire Dome project located in Waller County Texas,

•    $.5 million on additional land activity in our West Broussard prospect,

•    $.7 million expended on the recompletion and rework of our West Cameron Block 49 production and

•    $.4 million for drilling, remedial and rework activity in the Mid-Continent area.

 

Since 2000, our working capital and liquidity have significantly decreased due to intensified drilling and lease acquisition activity, which primarily occurred in the last half of 2001.  This activity was funded from:

 

•    cash flow from operations,

•    funds received from our 2001 preferred stock private placement, and

•    proceeds from the sale of certain evaluated and unevaluated oil and gas properties.

 

Approximately $15.6 million was expended during 2001 on our exploration and development program, including the acquisition of additional working interests in production and leasehold acreage, both evaluated and unevaluated.  The results from our exploration program have been disappointing in regards to the discovery of any significant fields or extensions.

 

In 2002, due to no significant proved producing reserve additions, our borrowing base capacity under the current credit facility, which was acquired through the Red River Energy acquisition, has not increased and is not a material source of capital.  However, historically we have not used credit facilities for a source of funds in our drilling or leasing activity.  Should proved developed reserves not materially increase and/or pricing decline, our borrowing base may be reduced below the amount currently borrowed and outstanding under this facility.  If this event occurs we would be obligated to pay down the outstanding amount to the re-determined borrowing capacity. We would rely on cash flow from operations and possibly funds generated from the sale of unevaluated prospects to make this pay down. It is possible that we would have to sell some non-core assets as well in order to meet this obligation.  The current credit agreement has a maturity date of March 15, 2004 and the next re-determination will take place in late March 2003.  At December 31, 2002, our borrowing capacity was $14,500,000 and a balance of $13,634,652 was outstanding against the borrowing base. Our effective interest rate, which is a LIBOR base rate plus 2.2%, was approximately 3.7%.  We expect to extend the maturity date of the revolving credit agreement to April 2005 and maintain the current collateral borrowing base of $14,500,000.

 

Our principal source of short-term liquidity for 2003 will be our operating cash flow.  Our short-term liquidity and working capital should steadily increase in 2003 due to a lower capital expenditure program and the prospect of stronger natural gas and crude oil prices.  An additional source of short-term liquidity may come in the form of funds received from the sale of all or a portion of our interests in certain unevaluated projects or non-core assets.  We intend to further reduce our working interest in certain unevaluated projects to enhance our risk profile and improve our cash position and working capital.

 

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.

 

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		Payments Due by Period
Contractual Obligations		Total			Less than 1 year			1-3 years			4-5 years			After 5 years
Long — Term Debt (1)		$	13,705,483		$	70,831		$	13,634,652		$	—		$	—
Operating Leases (2)		183,579			155,723			27,856			—			—
Total cash obligations		$	13,889,062		$	226,554		$	13,662,508		$	—		$	—

 

(1)             $13,634,652 is 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.  We expect to extend the maturity date of the revolving credit agreement to April 2005 and maintain the current collateral borrowing base of $14,500,000.

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

 

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

 

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

 

Accounting Policies

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

 

•              Use of estimates

•              Oil and gas properties

•              Derivative instruments and hedging activity

•              Concentration of credit risk

 

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

 

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

 

Oil and gas properties - - We account for our oil and gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”).  Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized.  All general corporate costs are expensed as incurred.  In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded.  Amortization of evaluated oil and gas properties is computed on the 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

 

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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  2002, unevaluated leasehold costs were impaired for $1,632,174 and transferred to U.S. evaluated costs, or the full cost pool.  For the remaining costs, which includes seismic and geological and geophysical, we estimate reserve potential for the unevaluated properties using comparable producing areas or wells and risk that estimate by 50-75%.  As mentioned previously in Use of Estimates, reserve estimations are more imprecise for new or unevaluated areas.  Consequently, should certain geological conditions or factors exist, such as reservoir depletion, reservoir faulting, reservoir quality etc., but unknown to us at the time of our assessment, a materially different result could occur.

 

Derivative instruments and hedging activity — We use derivatives in a limited manner to protect against commodity price volatility.  Effectively, we sell a portion of our natural gas and crude oil based on a NYMEX based price with a set floor (bottom) and ceiling (top) price or a range.  Our derivatives are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of transaction.  Our derivative contracts consist of cash flow hedge transactions 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 FASB Statement No. 123 Accounting for Stock-Based Compensation (FASB 123) and related interpretations in accounting for our employee and director stock options.  Under FASB Statement No. 148 Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment to FASB 123, certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation if adopted in a fiscal year beginning before December 16, 2002.  We will use the prospective method which will apply prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted.

 

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

 

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Plan of Operation for 2003

 

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

 

We project our 2003 capital expenditure to be approximately $3 million.  The areas and amounts of concentration

for the capital program will be:

 

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

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

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

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

•              McIntosh County, Oklahoma - $.1 million

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

•              Other - $.2 million

 

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

 

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

 

1)              We have approximately 375,725 callable common stock purchase warrants outstanding exercisable at a price of $7.50 per share.  We are able to call these warrants at any time after our common stock has traded on Nasdaq at a market price equal to or exceeding $10.00 per share for 10 consecutive days which was achieved in July 2000.  It is our intent to call all of these warrants at such time, if and when, the cash is needed to fund capital requirements.  We will receive proceeds equal to the exercise price times the number of shares which are issued from the exercise of warrants net of commission to the broker of record, if any.  We could realize net proceeds of

 

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approximately $2,814,500 from the exercise of all of these warrants.  There is no assurance that any warrants will be exercised or that we will ever realize any proceeds from the $7.50 warrant calls.  However, due to current market conditions and the current price of our stock, it is not probable that we will call these warrants in 2003.

 

2)              We may seek mezzanine financing, if available, on terms acceptable to us.  Mezzanine financing usually involves debt with a higher cost of capital as compared to conventional bank financing.  We would seek mezzanine financing in the range of $1,000,000 to $5,000,000.   We would seek to use this means of financing in the event that a particular acquisition or project did not have sufficient proved producing reserve collateral to support a conventional bank loan.

 

3)              We may realize additional cash flow from oil and gas wells to be drilled, if found to be productive.  We own working interests in wells that are currently producing and in additional wells, which are currently drilling or scheduled to be drilled in 2003.  Additional cash flow from those wells that are drilling or scheduled to be drilled in 2003 is not considered in our current projection.

 

If the above additional sources of cash are insufficient or are unavailable on terms acceptable to us, we will be compelled to reduce the scope of our business activities.   If we are unable to fund planned expenditures within a thirty to sixty-day period after a well is proposed for drilling, it may be necessary to:

 

1)     Forfeit our interest in wells that are proposed to be drilled;

2)     Farm-out our interest in proposed wells;

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

4)     Reduce general and administrative expenses.

 

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

 

Our long-term goal is to grow the Company by accumulating oil and gas reserves through exploitation of our existing assets, acquisitions and/or exploratory drilling.  In the event we cannot raise additional capital, or the industry market is unfavorable, we may have to slow or alter our long-term goal accordingly.  Should we achieve our long-term goal and an acceptable value for our shareholders is recognized over the next two to three years, selling a portion or all of the Company is a possibility.

 

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

 

Comparison of Results of Operations

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.

 

 

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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 volume 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 back on line 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 indexed-based price.  These indices are generally affected by the NYMEX — Henry Hub spot price.  We use hedges on a limited basis to lessen the impact of price volatility.  Hedges covered approximately 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 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 (for further discussion please refer to Item 3. Legal Proceedings).  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.

 

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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.

 

Year ended December 31, 2001 and Compared to Year ended December 31, 2000

We had a reported net loss of ($9,046,084) for the year ended December 31, 2001 compared to net income of $1,425,565 the same period ended 2000.  Our results of operations for 2001 included full cost ceiling impairments at September 30, 2001 of  $6,770,110  and at December 31, 2001 of $7,034,925 .  The full cost ceiling impairments were a result of declining natural gas and crude oil prices in the last half of 2001 and marginal success with our exploration program during the year.  At December 31, 2001 and at September 30, 2001, the total cost of our U.S. evaluated properties exceeded their net realizable value, based on December 31, 2001 and September 30, 2001 prices, respectively, and accordingly non-cash write downs were recorded as required by SEC rules.  Net income, excluding the full cost ceiling impairments, for the year 2001 was $904,224 compared to net income of $1,425,565 for the year 2000.  Higher depletion expense and operating expense and a non-recurring charge of $205,415 relating to the settlement of a gas contract dispute contributed to the lower net income for 2001.

 

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

 

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For the year ended December 31, 2001, oil and gas sales increased  $4,750,881 or 59%, from the year ended 2000, to $12,788,115.  Increased production volume of natural gas and crude oil resulted in additional revenues of $5,701,359 or a 71% increase in oil and gas sales for 2001 compared to 2000.  Of the increase in oil and gas sales due to higher production volume, natural gas comprised 56% of the increase while crude oil accounted for the remaining 44%.  The increase in the production volume for the year ended 2001, compared to the same period for 2000, was due to acquired production in the Red River Energy acquisition and new wells connected in the 2001 and the last of half of 2000.  However, lower natural gas and crude oil prices for 2001 resulted in lower revenues of approximately $950,478, or a 12% decrease in oil and gas sales for 2001 compared to 2000.  Of the decrease in oil and gas sales due to lower prices, natural gas comprised 30% of the decrease with lower crude oil prices accounting for the remaining 70%.

 

Generally, we sell our natural gas to various purchasers on an indexed-based price.  These indices are generally affected by the NYMEX — Henry Hub spot price.  We use hedges on a limited basis to lessen the impact of price volatility.  Hedges covered approximately 27% of our production on an equivalent Mcf basis for the year ended December 31, 2001.  Based on our natural gas production for the twelve months ended December 31, 2001, a decline in the average natural gas price realized by Beta of $1.00 per Mcf would have resulted in an approximate  $2.5 million reduction in net income before income taxes.

 

Operating expenses, including production and ad valorem taxes, increased $2,100,406, or 153%, to $3,469,194 for the year ended December 31, 2001 compared to the same period for 2000.  The increased expenses were due to additional operating expenses associated with the Red River Energy acquisition properties, higher production and severance taxes from increased oil and gas sales and an increase in number of wells put on production during 2001 and the last half of 2000.  The average operating expense, including production tax, for the Red River Energy acquisition oil and gas properties was approximately $1.39 per equivalent Mcf for the year ended December 31, 2001.  The operating cost per equivalent Mcf is significantly higher for the Red River Energy acquisition oil and gas properties as compared to the operating cost for the remaining properties ($.58 per equivalent Mcf) due to the Red River Energy acquisition properties being older in production life and the necessity to dispose of a significant volume of salt water produced.  Additionally, due to the age of the properties, repair and maintenance costs are higher than that of the other properties.

 

Field service expense relates to the operation of our McIntosh County, OK gathering system that was acquired in the Red River Energy acquisition.  The increase in expense for 2002 was due to having the system for twelve months versus four months in 2001.

 

General and administrative expenses for the twelve months ended December 31, 2001 increased approximately  $538,116, or 25%, to $2,679,121 compared to $2,141,005 for the same period in 2000.  The increase was due to 1.) a non-recurring charge of $205,415 relating to the settlement of a gas contract dispute (for further discussion please refer to Item 3. Legal Proceedings) and 2.), increased salary and associated personnel expense related to personnel hired in the Red River

 

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Energy acquisition and outside services, which provided operational accounting services for the properties from the Red River Energy acquisition, and overall increase in corporate activity for the year.

 

Depletion and depreciation expense increased $2,483,458, or 92%, from the same period in 2000 to $5,176,897 for the twelve months ended December 31, 2001. Depletion associated with evaluated oil and gas properties comprised $2,254,036, or 91%, of this increase.  Depletion for oil and gas properties is calculated using the “Unit of Production” method, which essentially amortizes the capitalized costs associated with the evaluated properties based on the ratio of production volume for the current period to total remaining reserve volume for the evaluated properties.  Therefore, due to the increase in production volume for the year ended December 31, 2001 compared to the same period ended 2000 and increased costs for our evaluated properties due to the drilling activity during the year, depletion expense increased.  Depletion expense on a per Mcf equivalent basis for the twelve months ended December 31, 2001 was $1.51 per Mcf compared to $1.35 per Mcf for the same period in 2000.   Depreciation expense, related to other assets, for the twelve months ended December 31, 2001 was $318,533, or $.09 per Mcf, compared to $89,111, or $.05 per Mcf, for the same period in 2000 or an increase of $229,422.  Of the increase, $195,033 was related to gathering assets acquired in the Red River Energy acquisition, which are depreciated separately from the oil and gas properties.  Furniture, fixtures and other equipment comprised the remainder of the increase.

 

At December 31, 2001 and September 30, 2001, the total capitalized costs for the U.S. evaluated properties full cost pool exceeded the net realizable value of the properties and accordingly 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 since December 31, 2000 and higher future operating expenses regarding production on the older properties.  The prices used in the determination on 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 increased for twelve months ended December 31, 2001, compared to the same period 2000 as a result of the debt acquired in the Red River Energy acquisition.  The increase was partially offset by lower interest rates for 2001 compared to the rates in effect for 2000.

 

Income Taxes

As of December 31, 2002, we had available, to reduce future taxable income, a Federal net operating loss carryforward of approximately $20,771,000, which expires in the years 2012 through 2022.  Utilization of the tax net operating loss carryforward may be limited in the event a 50% or more change of ownership occurs within a three-year period.  The tax net operating loss carryforward may be limited by other factors as well.  As of December 31, 2002, we had no deferred taxes.

 

Impact of Recently Issued Standards

In June 2001, the FASB also approved for issuance SFAS 143 “Asset Retirement Obligations.”  SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures.  SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.  We will adopt the statement effective no later than January 1, 2003, as required.  The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle.  At December 31, 2002, the impact of the adoption would have resulted in a $1,640 favorable adjustment to income.  The asset retirement obligation will be approximately $913,550.

 

In August 2002, the FASB issued Statements of Financial Accounting Standards No. 147, “Acquisitions of Certain Financial Institutions” (SFAS 147).  SFAS 147 requires financial institutions to follow the guidance in SFAS 141 and SFAS 142 for business combinations and goodwill and intangible assets, as opposed to the previously applied accounting literature.  This statement also amends SFAS 144 to include in its scope long-term customer relationship intangible assets of financial institutions.  The provisions of SFAS 147 do not apply to the Company.

 

In December 2002, the FASB issued Statements of Financial Accounting Standards No.148, “Accounting for Stock-Based compensation — Transition and Disclosure — an amendment of FASB Statement 123” (SFAS 123).   For entities that change their accounting for stock-based compensation from the intrinsic method to the fair value method under SFAS 123,

 

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the fair value method is to be applied prospectively to those awards granted after the beginning of the period of adoption (the prospective method).  The amendment permits two additional transition methods for adoption of the fair value method.  In addition to the prospective method, the entity can choose to either (i) restate all periods presented (retroactive restatement method) or (ii) recognize compensation cost from the beginning of the fiscal year of adoption as if the fair value method had been used to account for awards (modified prospective method).  For fiscal years beginning after December 15, 2003, the prospective method will no longer be allowed.  The Company currently accounts for its stock-based compensation using the intrinsic value method as prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”.

 

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.  Based on the month December 2002 production rate, we have approximately 63% of our current natural gas production hedged for January and February 2003 decreasing to approximately 31% for the period March 2003 through August 2003.  For crude oil, we have approximately 58% of our current monthly production hedged through March 2003 decreasing to approximately 29% for the period April 2003 through September 2003.  We use costless collars and swaps to hedge our production.  For more information please refer to Item 8.  Financial Statements And Supplementary Data, Note 6. Derivative And Hedging Activities.  The remainder of our production is not hedged and we may continue to experience wide fluctuations in oil and gas revenues as a result.  We are also exposed to market risk related to adverse changes in interest rates.  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.

 

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

 

None.

 

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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 2003 annual meeting under the headings “Proposal One — Election of Directors,” “Executive Officers” and “Section 16(a) Beneficial Ownership Reporting Compliance.”

 

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 2003 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 2003 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 2003 annual meeting under the heading “Certain Transactions.”

 

Item 14.  Controls and Procedures

 

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

 

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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.

 

INDEX TO EXHIBITS

 

EXHIBIT NUMBER			DESCRIPTION
3.1			Original Articles of Incorporation of Registrant incorporated by reference to Exhibit 3.1 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/ 001059324-98-000005.txt).
3.2			Amended and Restated Bylaws of the Registrant, Dated October 29, 1998, incorporated by reference to Exhibit 3.2 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/ edgar/data/1059324/0001059324-98-000005.txt).
3.3			Certificate of Amendment of Articles of Incorporation of the Registrant, dated August 28, 2000, incorporated by reference to Exhibit 3.1 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/ 0001021890-01-500087.txt)
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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.4			T.A.C. Resources Agreement, Dated January 21, 1998, incorporated by reference to Exhibit 10.4 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.5			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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.6			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 at ( http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.7			Stansbury Basin (Australia) Prospect Agreement, Dated February 1998, incorporated by reference to Exhibit 10.7 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.9			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 at ( http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.14			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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.19			Redfish Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.19 of Beta’s

 

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		Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/ Archives/edgar/data/1059324/0001059324-99-000011.txt).
10.20		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 at ( http://www.sec.gov/ Archives/edgar/data/1059324/0001059324-99-000011.txt).
10.21		Cheniere Energy, Inc. Option Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.21 of Beta’s Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.22		Dyad-Australia, Inc. Agreement Dated January 25, 1999, incorporated by reference to Exhibit 10.22 of Beta’s Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/ Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.24		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 at ( http://www.sec.gov/Archives/edgar/data/1059324/ 0001059324-00-000007.txt)
10.25		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 at  http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-00-000007.txt)
10.27		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 at ( http://www.sec.gov/Archives/edgar/ data/1059324/000105932400000042/0001059324-00-000052.txt).
10.29		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 at  (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
10.30		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 at  (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
10.31		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 at (http://www.sec.gov/Archives/edgar/data/ 1059324/000102189001500087/ 0001021890-01-500087.txt).
10.32		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 at (http://www.sec.gov/Archives/edgar/data/1059324/ 000102189001500087/0001021890-01-500087.txt).
10.33		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 at (http://www.sec.gov/Archives/edgar/ data/1059324/000102189001500087/0001021890-01-500087.txt).
10.34		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, 2001at (http://www.sec.gov/Archives/edgar/ data/1059324/000102189001500087/0001021890-01-500087.txt).
10.35		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 at (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
10.36		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.
10.37		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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/000105932400000042/0001059324-00-000042-0001.htm).
10.38		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

 

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		Quarter 2002 Form 10-Q filed August 14, 2002.
10.39		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.
10.40		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.
10.41		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.
21		List of Subsidiaries incorporated by reference to Exhibit 21 of Beta’s Form 10-K for the year 2000 filed  April 2, 2001 at (http://www.sec.gov/Archives/edgar/data/1059324/ 000102189001500087/0001021890-01-500087.txt).
23.2		Consent of Hein + Associates, LLP. dated March 27, 2003
23.3		Consent of Ryder Scott and Associates dated March 27, 2003
99.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

 

(b)  Form 8-K dated October 1,2002 reported Item 5. the appointment of Mr. David A. Wilkins as President and  Chief Executive Officer

 

Form 8-K dated December 30, 2002 reported Item 9. the Board of Directors approved a two-year extension of expiration dates for certain stock purchase warrants.

 

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INDEX TO FINANCIAL STATEMENTS

 

 

Independent Auditor’s Report

Consolidated Balance Sheets - December 31, 2002 and 2001

Consolidated Statements of Operations - For the Years Ended December 31, 2002, 2001 and 2000

Consolidated Statement of Stockholders’ Equity - For the Years Ended December 31, 2002, 2001 and 2000

Consolidated Statements of Cash Flows - For the Years Ended December 31, 2002, 2001 and 2000

Notes to Consolidated Financial Statements

 

F-1

 

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 2001, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-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 2001 and the results of their operations and their cash flows for each of the years in the three-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-2

 

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

		December 31, 2002			December 31, 2001
Current assets:
Cash		$	927,313		$	556,199
Accounts receivable
Oil and gas sales		1,676,935			1,397,532
Other		149,243			754,390
Income tax receivable		52,115			38,503
Futures transaction hedge asset		—			68,508
Prepaid expenses		187,818			187,495
Total current assets		2,993,424			3,002,627
Oil and gas properties, at cost (full cost method)
Evaluated properties		70,907,441			58,708,444
Unevaluated properties		4,582,605			13,001,443
Less — accumulated amortization and impairment of full cost pool		(35,133,445		)	(25,058,725		)
Net oil and gas properties		40,356,601			46,651,162
Other operating property and equipment, at cost
Gas gathering system		1,507,177			1,491,516
Support equipment		221,413			221,413
Other		215,302			198,520
Less — accumulated depreciation		(616,865		)	(408,430		)
Net other operating property and equipment		1,327,027			1,503,019
Other assets		76,208			1,472,570
Total assets		$	44,753,260		$	52,629,378
Current liabilities:
Current portion of long-term debt		$	70,831		$	57,407
Accounts payable, trade		1,909,226			2,472,203
Futures transaction hedge liability		702,417			—
Dividends payable		112,707			112,708
Other accrued liabilities		275,290			463,859
Total current liabilities		3,070,471			3,106,177
Long-term debt, less current portion		13,634,652			13,648,727
Commitments and contingencies (Notes 5, 6 and 9)
Stockholders’ equity
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,272 and 604,272 issued and outstanding at December 31, 2002 and 2001, respectively.  Liquidation value at December 31, 2002 is $5,702,097.		604			604
Common stock, $.001 par value; 50,000,000 shares authorized; 12,446,072 and 12,398,572 shares issued and 12,440,057 and 12,356,072 outstanding at December 31, 2002 and 2001, respectively		12,447			12,399
Additional paid-in capital		51,917,235			51,814,699
Treasury stock, at cost; 6,015 and 42,500 shares reacquired at December 31, 2002 and December 31, 2001, respectively		(28,153		)	(198,920		)
Accumulated other comprehensive income		(702,417		)	68,508
Accumulated deficit		(23,151,579		)	(15,822,816		)
Total stockholders’ equity		28,048,137			35,874,474
Total liabilities and stockholders’ equity		$	44,753,260		$	52,629,378

 

See accompanying notes to consolidated financial statements.

 

F-3

 

BETA OIL & GAS, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF OPERATIONS

 

 

		For the years ended December 31,
		2002			2001			2000
Revenues:
Oil and gas sales		$	9,244,530		$	12,788,115		$	8,037,234
Field services		403,311			868,406			320,633
Total revenue		9,647,841			13,656,521			8,357,867
Costs and expenses:
Lease operating expense		3,304,921			3,469,194			1,368,788
Field services		195,430			339,329			147,325
General and administrative		2,209,887			2,679,121			2,141,005
Full cost ceiling impairment		5,163,689			13,805,035			—
Depreciation and amortization expense		5,120,572			5,176,897			2,693,439
Total costs and expenses		15,994,499			25,469,576			6,350,557
Income (loss) from Operations		(6,346,658		)	(11,813,055		)	2,007,310
Other income (expense):
Interest expense		(558,297		)	(867,835		)	(393,008		)
Interest income and other		23,343			130,374			105,563
Total other income (expense)		(534,954		)	(737,461		)	(287,445		)
Income (loss) before tax provision		(6,881,612		)	(12,550,516		)	1,719,865
INCOME TAX BENEFIT (PROVISION)		—			3,504,432			(294,300		)
Net income (loss)		(6,881,612		)	(9,046,084		)	1,425,565
Preferred dividends		(447,151		)	(231,821		)	—
Net income (loss) available to common shareholder		$	(7,328,763	)	$	(9,277,905	)	$	1,425,565
Basic net income (loss) per common share		$	(.59	)	$	(.75	)	$	0.13
Diluted net income (loss) per common share		$	(.59	)	$	(.75	)	$	0.13
Comprehensive Income (loss):
Net Income  (loss)		$	(6,881,612	)	$	(9,046,084	)	$	1,425,565
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)		829,248			340,048			—
Unrealized gain (loss) on qualifying cash flow hedges (net of income taxes)		(1,600,173		)	681,948			—
Total Comprehensive Income (Loss)		$	(7,652,537	)	$	(8,977,576	)	$	1,425,565

 

See accompanying notes to consolidated financial statements.

 

F-4

 

BETA OIL & GAS INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENT OF STOCKHOLDERS’EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000

               

												Additional Paid In Capital			Treasury Stock			Accumulated   Comprehensive Income			Accumulated Deficit			Total Stockholders’ EQUITY
		Preferred					Common
		shares		amount			shares		amount
Balances, January 1, 2000		—		$	—		9,400,124		$	9,400		$	28,549,313		$	—		$	—		$	(7,970,476)		$	20,588,237
Issuance of shares for warrant exercises		—		—			665,827		666			3,114,473			—			—			—			3,115,139
Issuance of shares for option exercises		—		—			15,000		15			89,985			—			—			—			90,000
Issuance of shares upon merger		—		—			2,250,000		2,250			14,352,750			—			—			—			14,355,000
Issuance of shares for purchase of note		—		—			10,000		10			86,240			—			—			—			86,250
Warrants issued for purchase of note		—		—			—		—			226,030			—			—			—			226,030
Warrants issued to consultants		—		—			—		—			128,338			—			—			—			128,338
Warrants issued for property		—		—			—		—			45,847			—			—			—			45,847
Net income		—		—			—		—			—			—			—			1,425,565			1,425,565
Balances, December 31, 2000		—		—			12,340,951		12,341			46,592,976			—			—			(6,544,911		)	40,060,406
Issuance of shares pursuant toprivate placement, net		604,272		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		604,272		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 (net of income taxes)		—		—			—		—			—			—			829,248			—			829,248
Unrealized gain (loss) on qualifying cash flow hedges (net of income taxes)		—		—			—		—			—			—			(1,600,173		)	—			(1,600,173		)
Net loss		—		—			—		—			—			—			—			(6,881,612		)	(6,881,612		)
Balances, Dec. 31, 2002		604,272		$	604		12,446,072		$	12,447		$	51,917,235		$	(28,153	)	$	(702,417	)	$	(23,151,579	)	$	28,048,137

 

See accompanying notes to consolidated financial statements.

 

F-5

 

BETA OIL & GAS INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

		For the years ended December 31,
		2002			2001			2000
Cash Flows From Operating Activities:
Net income (loss)		$	(6,881,612	)	$	(9,046,084	)	$	1,425,565
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		5,120,572			5,176,897			2,693,439
Gain (loss) on sale of equipment		—			6,865			(2,915		)
Impairment expense		5,163,689			13,805,035			—
Deferred income tax		—			(3,526,304		)	—
Warrants issued to consultants		—			—			128,338
Compensation  associated with warrant extension		14,842			—			—
Change in operating assets and liabilities:
Accounts receivable		325,744			709,922			(1,140,077		)
Income tax receivable		(13,612		)	(38,503		)	—
Prepaid expenses		(323		)	13,120			(45,109		)
Accounts payable, trade		(562,979		)	1,828,791			535
Income taxes payable		—			(198,650		)	198,650
Other accrued expenses		(188,569		)	316,006			(29,345		)
Net cash provided by operating activities		2,977,752			9,047,095			3,229,081
Cash Flows From Investing Activities:
Oil and gas property expenditures		(6,838,779		)	(14,927,031		)	(6,666,327		)
Proceeds received from sale of oil and gas properties		3,229,388			1,065,989			—
Gas gathering and equipment expenditures		(36,103		)	(177,103		)	(92,203		)
Cash acquired in merger		—			—			895,097
Proceeds received from equipment sale		2,556			16,535			100,000
Change in other assets		1,396,361			(726,430		)	(278,287		)
Net cash used in investing activities		(2,246,577		)	(14,748,040		)	(6,041,720		)
Cash Flows From Financing Activities:
Proceeds from exercise of warrants and options		95,000			180,857			3,205,139
Proceeds from premiums payable		233,637			152,680			51,409
Repayment of premiums payable		(221,401		)	(174,284		)	(27,737		)
Proceeds from notes payable		—			900,000			295,376
Repayment of notes payable		(12,887		)	(1,061,789		)	(624,017		)
Proceeds from preferred stock private placement		—			5,589,390			—
Offering costs for preferred stock private placement		(7,258		)	(547,862		)	—
Acquisition of treasury stock		—			(198,920		)	—
Dividends paid		(447,152		)	(119,114		)	—
Net cash provided by (used in) financing activities		(360,061		)	4,720,958			2,900,170
Net Increase (Decrease) in Cash and Cash Equivalents		371,114			(979,987		)	87,531
Cash and Cash Equivalents, at beginning of period		556,199			1,536,186			1,448,655
Cash and Cash Equivalents, at end of period		$	927,313		$	556,199		$	1,536,186
Supplemental Disclosure of Cash Flow Information
Cash paid for:
Interest		$	515,524		$	867,835		$	393,009
Income taxes		$	13,612		$	236,000		$	46,375
Supplemental Disclosure Of Non-cash Investing And Financing Activities
Fair value of common stock and warrants issued for:
Net assets acquired, net of cash, through acquisition of RRE		$	—		$	—		$	13,459,903
Oil and gas properties		$	170,267		$	—		$	45,847
Common stock and warrants issued in settlement of debt		$	—		$	—		$	312,280

 

See accompanying notes to consolidated financial statements.

 

F-6

 

BETA OIL & GAS INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.                      Business and Summary of Significant Accounting Policies:

 

Consolidation - Beta Oil and Gas, Inc. is engaged in the business of acquiring, exploring and developing oil and gas properties.  All of the Company’s operating income is derived from core areas located in Texas, Oklahoma, Kansas and Louisiana.  The Company, through one of its wholly owned subsidiaries owns a 25% interest in an undeveloped concession located in Western Queensland, Australia.  The accompanying consolidated financial statements include the accounts of Beta Oil & Gas, Inc. and its wholly owned subsidiaries.  All significant intercompany accounts and transactions have been eliminated in consolidation.

 

Use of Estimates - - The preparation of the Company’s consolidated financial statements in conformity with generally accepted accounting principles requires the Company’s 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.  Management emphasizes 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.

 

Oil and Gas Properties - The Company accounts for its oil and gas producing activities using the full cost method of accounting as prescribed by the United States Securities and Exchange Commission (“SEC”). Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals are capitalized.  All general corporate costs are expensed as incurred.  In general, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded.  Amortization of evaluated oil and gas properties is computed on the units of production method based on all proved reserves on a country-by-country basis.  Unevaluated oil and gas properties are assessed at least annually for impairment either individually or on an aggregate basis.  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.

 

Joint Ventures - All exploration and production activities are conducted jointly with others and, accordingly, the accounts reflect only the Company’s proportionate interest in such activities.

 

Revenue Recognition — The Company recognizes oil and gas sales upon delivery to the purchaser.  Under the sales method, the Company and other joint owners may sell more or less than their entitled share of the natural gas volume produced.  Should the Company’s excess sales of natural gas exceed its share of estimated remaining recoverable reserves a liability is recorded and revenue is deferred.

 

F-7

 

Other Operating Property and Equipment — Other operating property and equipment are stated at cost.  Provision for depreciation and amortization on property and equipment is calculated using the straight-line and accelerated methods over the estimated useful lives (ranging from 3 to 5 years) of the respective assets.  Amortization from the gathering assets is computed on a units of revenue method based on the total future gross revenues.  The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures, which increase the life of an asset, are capitalized and depreciated over the estimated remaining useful life of the asset.  The cost of properties sold, or otherwise disposed of, and the related accumulated depreciation or amortization are removed from the accounts, and any gain or losses are reflected in current operations.

 

Impairment of Long-Lived Assets - - In the event that facts and circumstances indicate that the costs of long-lived assets, other than oil and gas properties, may be impaired, an evaluation of recoverability would be performed.  If an evaluation is required, the estimated future undiscounted cash flows associated with the asset would be compared to the asset’s carrying amount to determine if a write-down to market value or discounted cash flow value is required.  Impairment of oil and gas properties is evaluated subject to the full cost ceiling as described under oil and gas properties.

 

Income Taxes — The Company accounts for income taxes using the asset and liability method wherein deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled.

 

Concentrations of Credit Risk - - Credit risk represents the accounting loss that would be recognized at the reporting date if counterparties failed completely to perform as contracted.  Concentrations of credit risk (whether on or off balance sheet) that arise from financial instruments exist for groups of customers or counter parties when they have similar economic characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in economic or other conditions described below.

 

The Company operates in one segment, the oil and gas industry.  A geographic concentration exists because the Company’s customers are generally located within the Central United States.  Financial instruments that subject the Company to credit risk consist principally of oil and gas sales which are based solely on short-term purchase contracts from various customers with related accounts receivable subject to credit risk.

 

The table below shows the purchasers that each accounted for 10% or more of the Company’s revenue during the specified years.

 

 

We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil

 

F-8

 

and gas we produce.  Other purchasers are available in our areas of operations.

 

Fair Value of Financial Instruments - - The estimated fair values for financial instruments under FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, are determined at discrete points in time based on relevant market information.  These estimates involve uncertainties and cannot be determined with precision.  The estimated fair value of cash, cash equivalents, accounts receivable and accounts payable approximates their carrying value due to their short-term nature.  The estimated fair value of long-term debt approximates its carrying value because the debt carries interest rates, which approximate market rates.

 

Stock Based Compensation — The Company has elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (APB25) and related interpretations in accounting for its employee stock options.  However, as required by FASB Statement No. 123 Accounting for Stock-Based Compensation (FASB123), the Company will disclose on a proforma basis the impact of the fair value accounting for employee stock options.  Transactions in equity instruments with non-employees for goods or services have been accounted for using the fair value method as prescribed by FASB123.

 

Derivative and Hedging Activities — In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133 (SFAS No.133), “Accounting for Derivative Instruments and Hedging Activities.”  The FASB has subsequently issued Statements No. 137 and Statement No. 138 which are amendments to SFAS No. 133.  SFAS No. 133, as amended, is effective for fiscal years beginning after June 15, 2000 and cannot be applied retroactively.  The Company adopted SFAS No. 133, as amended, beginning January 1, 2001.

 

SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities.  All derivatives will be recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of transaction.  The Company’s derivative contract consists of a cash flow hedge transaction in which it hedges the variability of cash flow related to a forecasted transaction.  Changes in the fair value of these derivative instruments will be recorded in other comprehensive income and will be reclassified as earnings in the periods in which earnings are impacted by the variability of the cash flows of the hedged item.  The ineffective portion related to basis changes and time value of all hedges will be recognized in current period earnings.

 

Earnings Per Share — Basic EPS is calculated by dividing the income or loss available to common shareholders by the weighted average number of shares outstanding for the period.  Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

 

Statement of Cash Flows - - For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

 

F-9

 

New Accounting Pronouncements — In June 2001, the FASB also approved for issuance SFAS 143 “Asset Retirement Obligations.”  SFAS 143 establishes accounting requirements for retirement obligations associated with tangible long-lived assets, including (1) the timing of the liability recognition, (2) initial measurement of the liability, (3) allocation of asset retirement cost to expense, (4) subsequent measurement of the liability and (5) financial statement disclosures.  SFAS 143 requires that an asset retirement cost should be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method.  The Company will adopt the statement effective January 1, 2003, as required.  The transition adjustment resulting from the adoption of SFAS 143 will be reported as a cumulative effect of a change in accounting principle.  At this time, the Company estimates a cumulative effect from the change will be a favorable $1,640 adjustment and an asset retirement obligation of approximately $913,550 will be recorded at January 1, 2003.

 

In August 2002, the FASB issued Statements of Financial Accounting Standards No. 147, “Acquisitions of Certain Financial Institutions” (SFAS 147).  SFAS 147 requires financial institutions to follow the guidance in SFAS 141 and SFAS 142 for business combinations and goodwill and intangible assets, as opposed to the previously applied accounting literature.  This statement also amends SFAS 144 to include in its scope long-term customer relationship intangible assets of financial institutions.  The provisions of SFAS 147 do not apply to the Company.

 

In December 2002, the FASB issued Statements of Financial Accounting Standards No.148, “Accounting for Stock-Based compensation — Transition and Disclosure — an amendment of FASB Statement 123” (SFAS 123).   For entities that change their accounting for stock-based compensation from the intrinsic method to the fair value method under SFAS 123, the fair value method is to be applied prospectively to those awards granted after the beginning of the period of adoption (the prospective method).  The amendment permits two additional transition methods for adoption of the fair value method.  In addition to the prospective method, the entity can choose to either (i) restate all periods presented (retroactive restatement method) or (ii) recognize compensation cost from the beginning of the fiscal year of adoption as if the fair value method had been used to account for awards (modified prospective method).  For fiscal years beginning after December 15, 2003, the prospective method will no longer be allowed.  The Company currently accounts for its stock-based compensation using the intrinsic value method as proscribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees”.

 

2.                      Acquisitions, sales and Oil and Gas Operations:

 

Acquisitions and sales — On August 30, 2000, the Company closed the previously reported Agreement and Plan of Merger (“Agreement”) to acquire 100% interest in Red River Energy, Inc. (“RRE”)(now Beta Operating Company, L.L.C.).  The acquisition was consummated through a merger (“Merger”) between Beta Acquisition Company, Inc., a wholly owned subsidiary of the Company, and RRE following approval of the Agreement.  The effective date of the Merger was September 1, 2000.The acquisition, recorded under the purchase method of accounting, included the acquisition of the net assets of RRE with a value calculated to be $14,355,000 assuming an average Beta common stock price of $6.38 per share with 2,250,000 shares issued to the stockholders of RRE.  The purchase price has been allocated to assets acquired and liabilities assumed of RRE based on their estimated fair values, which approximated book values, except for evaluated oil and gas properties which were increased by $13,459,903 to their estimated fair value which was determined based on a September 1, 1999 independent reserve report.  This amount has been included in the full cost amortization base of the Company.  The actual results of operations

 

F-10

 

from RRE have been included in the accompanying financial statements since the effective date of the Merger, September 1, 2000.

 

On September 19, 2000, the Company issued 10,000 shares of common stock, granted 100,000 callable common stock purchase warrants and gave a cash payment of approximately $560,000 to Duke Field Services, L.L.C. (“Duke”) in consideration for the purchase of Duke’s interest in the TCM coalbed properties and a note payable due Duke with a principal balance, including interest, of $2,270,000.  The callable common stock purchase warrants were valued, as calculated under the Black-Scholes valuation model with a volatility of 53.9%, risk free interest rate of 6.11% and an estimated time to expire of three years, at $226,030.  The warrants vest immediately, expire on September 19, 2004 and have an exercise price of $10.78.  The gain on extinguishment of debt of approximately $1,395,000 was applied against the fair value of the TCM coalbed properties as a purchase price allocation as the coalbed properties were acquired by Beta through the merger with RRE as described herein.

 

In June 2001, the Company sold its 40% working interests in certain oil and gas properties, which represented less than 1% of the Company’s proved reserves, for $710,000.  The properties were located in Pecos County, Texas.

 

In June 2001, the Company purchased additional working interests in certain oil and gas properties located in the Brookshire Dome area, Waller County Texas, in which it had existing working interests, for approximately $726,600.  However, certain existing working interest owners in these properties exercised their preferential right to purchase their pro-rata share of the interests originally purchased by the Company.  Upon the exercise of this right in August 2001, the Company was reimbursed by the other owners approximately $454,100 of its original acquisition cost.  The Company’s net acquisition cost, after reimbursement, was approximately $272,500 for an approximate 11.71% working interest.  The proved reserves associated with this acquisition were less than 1% of the Company’s total proved reserves.

 

In August 2001, the Company acquired an additional 15% working interest in its Brookshire Dome, Waller County, Texas leasehold acreage and producing properties for approximately $580,000.  After the effect of the acquisition, the Company’s total working interest in this prospect is approximately 40%, subject to a 10% “back-in” interest which reverts to the seller after the project payout, as defined in the purchase and sale agreement.

 

In December 2001, the Company sold a portion of its interests in two unevaluated properties, located in Jackson County and Galveston County, Texas, for $356,000.  The Company retained an approximate 16% interest in its Matterhorn, Jackson County prospect and an approximate 34% interest in its Sara White, Galveston County prospect.  Both prospects were drilling at December 31, 2001 and are currently in the completion stage.

 

F-11

 

In 2002, the Company sold interests in various internally generated prospects, unevaluated acreage and minority interests in non-core marginal producing properties for  $3,229,388 and certain drilling promotes.  The prospects were ready for sale as the Company had completed the leasing activity in late 2001.   The properties were as follows:

 

1.)   Lake Boeuf prospect, Lafourche Parish, Louisiana — 87.5% of the Company’s 100% interest was sold with the Company retaining a 12.5% working interest after casing point.   The Company received cash and a drilling promote on the interest sold.  This acreage is 100% unevaluated and has no proved reserves.  Subsequent to December 31, 2002, the party which purchased 75% of the 87.5% working interest indicated they would not be able to fulfill their obligation to drill the prospect.  The Company retained the proceeds received from the party and is pursuing other parties which may be interested in purchasing the remaining working interest.

 

2.)   North Mexican Sweetheart prospect, Jackson County, Texas — Approximately 90% of the Company’s working interest in the acreage was sold in this deep Yegua prospect for approximately $145,000.  The Company retained a 12.5% working interest after payout of the initial test well.  This acreage was 100% unevaluated and had no proved reserves.

 

3.)   West Broussard prospect and surrounding acreage — The Company entered into an agreement with an industry partner in September 2002, whereby the partner has an option, but not an obligation, to drill one well in both the East and West units of the prospect, with the East unit well being the initial well.  Upon execution of the agreement, the Company received $650,000 for consideration of certain rights and information granted to the partner.  This payment represented a partial reimbursement of the Company’s cost in the prospect.  Under the terms of the agreement, the partner was required to make a second payment to the Company of $650,000 upon the partner’s election to drill the well in the East unit, which was made in November 2002.  The well in the East unit commenced drilling in the first quarter of 2003.  The Company has an approximate 4.8% working interest in the East unit well before payout, increasing to a 10.1% working interest after payout.   Should the partner elect to drill a well in the West unit, the Company will receive an additional $1,300,000.  The Company will retain its present working interest ownership in the West unit until such time, if any, that the partner exercises the option to drill.  The Company currently has an 84.6 % working interest in the West unit.  Previous to this agreement, approximately 15.4% working interest in the East and West units was sold for approximately $608,000.

 

4.)   Brookshire Dome, Waller County, Texas — The Company reduced its working interest in its unevaluated Brookshire Dome leasehold from 40% to 25% and received approximately $747,000.  There were no proved reserves associated with this acreage.

 

5.)   Mid-Continent region, Oklahoma and Kansas — Various interests were sold in several transactions during the third quarter.  The interests sold were in non-core marginal producing properties.  The proved reserves associated with these properties represented less than 1% of the Company’s total proved reserves.  Total proceeds received from these sales were approximately $317,300.

 

Oil and gas properties - The capitalized costs at year-end and costs incurred in oil and gas producing activities during the years were as follows:

 

F-12

 

		United States			Foreign			Total
2002 Capitalized costs:
Evaluated properties		$	69,226,520		$	1,680,921		$	70,907,441
Unevaluated properties		4,453,326			129,279			4,582,605
		73,679,846			1,810,200			75,490,046
Accumulated depreciation, depletion, amortization and impairment (1)		(33,452,175		)	(1,681,270		)	(35,133,445		)
Net capitalized costs		$	40,227,671		$	128,930		$	40,356,601
Cost incurred:
Property acquisition		$	—		$	—		$	—
Exploration (2)		3,300,070			460			3,300,530
Development (3)		1,006,987			—			1,006,987
Total costs incurred		$	4,307,057		$	460		$	4,307,517
2001 Capitalized costs:
Evaluated properties		$	57,027,523		$	1,680,921		$	58,708,444
Unevaluated properties		12,872,623			128,820			13,001,443
		69,900,146			1,809,741			71,709,887
Accumulated depreciation, depletion, amortization and impairment (4)		(23,377,455		)	(1,681,270		)	(25,058,725		)
Net capitalized costs		$	46,522,691		$	128,471		$	46,651,162
Cost incurred:
Property acquisition (5)		$	1,233,543		$	—		$	1,233,543
Exploration (6)		10,958,163			5,250			10,963,413
Development		1,664,086			—			1,664,086
Total costs incurred		$	13,855,792		$	5,250		$	13,861,042
2000 Capitalized costs:
Evaluated properties		$	42,717,576		$	1,680,921		$	44,398,497
Unevaluated properties		13,326,778			123,569			13,450,347
		56,044,354			1,804,490			57,848,844
Accumulated depreciation, depletion, amortization and impairment		(4,714,056		)	(1,681,270		)	(6,395,326		)
Net capitalized costs		$	51,330,298		$	123,220		$	51,453,518
Cost incurred:
Property acquisition (7)		$	30,658,876		$	—		$	30,658,876
Exploration		3,514,875			5,126			3,520,001
Development		480,109			—			480,109
Total costs incurred		$	34,653,860		$	5,126		$	34,658,986

 

(1)  At December 31, 2002, the total costs in the U.S. evaluated properties exceeded their net realizable values and accordingly an impairment writedown of $5,163,689 was recorded.

(2)  Net of $2,912,096 related to sale of unevaluated properties.

(3)  Net of $317,292 related to sale of evaluated properties.

(4)  At September 30, 2001 and December 31, 2001, the total costs in U.S. evaluated properties exceeded their net realizable values and accordingly write downs were recorded for $6,770,110 and $7,034,925, respectively.

(5)  Net of $710,000 related to sale of evaluated oil and gas properties.

(6)  Net of $355,989 related to sale of unevaluated oil and gas properties.

(7)  Includes $24,845,227 related to the properties acquired in the Merger and $3,526,304 related basis from deferred taxes.

 

F-13

 

Evaluated oil and gas properties

 

United States — During the year ended December 31, 2002, the Company participated in the drilling of 21 gross (3.87 net) wells, in which the property acquisition and exploration costs associated with the wells were either transferred to or recorded directly to evaluated properties.  Depletion expense was $4,911,032 or $1.63 per Mcfe.  Crude oil is converted to equivalent units of natural gas on the basis of one barrel of oil to six Mcf of natural gas.

 

At December 31, 2002, the Company recorded a non-cash impairment charge of $5,163,689 on its U.S. domestic evaluated properties due to the transfer of $4,883,031 from its unevaluated properties related to the Company’s Jackson County, Texas area.  Due to the 2002 drilling results in this area and the redirection of capital from this area, the number of prospects or leads in this area significantly decreased from the previous year resulting in a lower estimated fair value.  Additionally, the Company’s proved reserves decreased in the fourth quarter of 2002 due to the reclassification of the proved undeveloped (PUD) reserves associated with the Company’s West Broussard prospect, to a less certain reserve category.  At December 31, 2001, the West Broussard prospect had proved reserves of approximately 7.3 Bcf of natural gas and 122 MBbl of oil, or 8.1 Bcfe of natural gas.  The prices used for the reserve estimation at December 31, 2002 were $4.75 per Mcf for natural gas and $31.23 per barrel for crude oil.

 

During the year ended December 31, 2001, the Company participated in the drilling of 51 wells, of which 49 were evaluated and the property acquisition and exploration costs associated with the wells were transferred to evaluated properties.  Depletion expense was $4,858,364 or $1.51 per Mcfe.

 

At December 31, 2001, the Company recorded an additional non-cash impairment charge on its U.S. domestic evaluated properties of $7,034,925 due to a significant decline in the estimated present value of future net cash flows from these properties due to lower pricing and increased estimated future operating expenses and increased exploration costs in the fourth quarter of 2001.  The prices used for the estimation were $2.65 per Mcf for natural gas and $18.17 per barrel for crude oil.  The prices used for this estimation at December 31, 2000 were $10.14 per Mcf for natural gas and $26.06 per barrel for crude oil.

 

At September 30, 2001, the Company recorded a non-cash impairment charge on its U.S. domestic evaluated properties of $6,770,110 due to a significant decline in the estimated present value of future net cash flows from these properties as a result of lower natural gas and crude oil prices at September 30, 2001.  The prices used for the estimation were $2.20 per Mcf for natural gas and $23.50 per barrel for crude oil.

 

During the year ended December 31, 2000, Beta participated in the drilling of 21 wells and the property acquisition and exploration costs associated with the wells were recorded to evaluated properties.  Depletion expense was $2,604,328 or $1.35 per equivalent Mcfe.

 

Due to the volatility of commodity prices and/or exploration and development expenditures with no significant proved reserve additions, should natural gas and crude oil prices decline in the future, even if only for a brief period of time, it is possible that future impairments of oil and gas properties could occur.  The price measurement date is on the last day of the quarter or year-end and is required by SEC rules.

 

Foreign — There was no activity outside of the United States for the years ended December 31, 2002, 2001 and 2000.

 

The results of operations for producing activities are provided below:

 

F-14

 

		United States			Foreign			Total
2002:
Revenues		$	9,244,530		$	—		$	9,244,530
Production costs		(3,304,921		)	—			(3,304,921		)
Depreciation, depletion and amortization		(4,911,032		)	—			(4,911,032		)
Impairment expense		(5,163,689		)				(5,163,689		)
Results of operations for producing activities (excluding generative administrative,financing costs and income taxes)		$	(4,135,112	)	$	—		$	(4,135,112	)
2001:
Revenues		$	12,788,115		$	—		$	12,788,115
Production costs		(3,469,194		)	—			(3,469,194		)
Depreciation, depletion and amortization		(4,858,364		)	—			(4,858,364		)
Impairment expense		(13,805,035		)				(13,805,035		)
Results of operations for producing activities (excluding generative administrative,financing costs and income taxes)		$	(9,344,478	)	$	—		$	(9,344,478	)
2000:
Revenues		$	8,037,234		$	—		$	8,037,234
Production costs		(1,368,788		)	—			(1,368,788		)
Depreciation, depletion and amortization		(2,604,328		)	—			(2,604,328		)
Results of operations for producing activities (excluding generative administrative,financing costs and income taxes)		$	4,064,118		$	—		$	4,064,118

 

Unevaluated oil and gas properties

 

At December 31, 2002, 2001 and 2000, unevaluated properties consist of the following:

 

 

United States - As the Company’s properties are evaluated through exploration, they will be included in the amortization base.  Costs of unevaluated properties in the United States at December 31, 2002 represent property acquisition and exploration costs in connection with the Company’s South Texas and Louisiana prospects.  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 term of the primary leasehold.  In 2002, unevaluated leasehold costs of $1,632,174 were transferred to U.S. evaluated costs, or the full cost pool.

 

For the remaining unevaluated costs, which include seismic and geological and geophysical expenditures, the Company estimates reserve potential using comparable producing areas or wells.  Additional risk is then applied in order to address the imprecise nature of the reserve estimation.  Reserve estimations are more imprecise for new or unevaluated areas.  Consequently, should certain geological conditions or factors exist, such as reservoir depletion, reservoir faulting, questionable reservoir quality, etc., that are unknown to the Company at the time of its assessment, a materially

 

F-15

 

different result could occur.  The current status of these unevaluated properties is that seismic has been acquired, processed and reprocessed and has been interpreted through 2002 on the subject acreage within the prospects.  Drilling commenced on the prospects during the first quarter of 1999 and will continue in future periods.  As the prospects are evaluated through drilling in future periods, the property acquisition and exploration costs associated with the wells drilled will be transferred to evaluated properties and become part of the amortization, or full cost base.  Based on the drilling success rate associated with the 2002 mid-to-deeper prospects and the future commitment of less capital to this area, the number of remaining prospects or leads at December 31, 2002 was significantly lower than at December 31, 2001.  Therefore, approximately $4,883,000 of unevaluated cost associated with  Jackson County, Texas was transferred to U.S. evaluated costs in the fourth quarter 2002, which is subject to amortization.

 

Management anticipates that the planned activities for 2003 will enable the evaluation of 90% of the remaining unevaluated costs as of December 31, 2002.

 

Foreign — Costs of unevaluated properties outside the United States represents costs in connection with the acquisition of properties in Australia.  Due to the delay in drilling the Toko Syncline prospect management does not expect this cost to be evaluated until 2003.  The Company anticipates the drilling of one well on this concession, in which it will retain a 6% carried interest of its current 25% interest.

 

3.                      Other Operating Property and Equipment:

 

As a result of the Merger, other operating property and equipment were acquired, which included 40 miles of pipeline in Eastern Oklahoma.  For the years ended December 31, 2002, 2001 and 2000, the Company recorded depreciation expense of $111,720, $251,227 and $56,544, for these assets respectively.  The Company recorded an additional depreciation expense for other equipment, which includes furniture and fixtures, of $97,820, $67,306, and $32,567 for the years ended December 31, 2002, 2001 and 2000, respectively.

 

At December 31, 2002 and 2001, support equipment with a net book value of $347,172 was classified as idle.  In management’s opinion, the net book value of the idle equipment is not in excess of its net realizable value.

 

F-16

 

4.                      Long-Term Debt:

 

Long-term debt consisted of the following:

 

		December 31,
		2002			2001
Notes payable under financing agreements for insurance premiums, bearing interest at rates ranging from 4.39% to 5.50%, due in monthly installments totaling $18,932 including interest, with maturity dates beginning February 2003 through May 2003.		$	56,756		$	45,551
Note payable under a revolving credit agreement, due March 15, 2004, bearing interest at a LIBOR based rate plus 2.2% (3.6388% at December 31, 2002), accrued interest payable monthly, collateralized by substantially all oil and gas properties owned by one of the Company’s subsidiaries.  Additionally, the Company has guaranteed the debt.		13,634,652			13,634,652
Note payable, due in monthly installments of $1,230 including interest maturing on December 19, 2003, collateralized by equipment.		14,075			25,931
		13,705,483			13,706,134
Less current portion		(70,831		)	(57,407		)
		$	13,634,652		$	13,648,727

 

The $13,634,652 note at December 31, 2002 arises from a credit agreement with a commercial bank that provides for maximum outstanding borrowings of up to  $25 million limited to a collateral borrowing base of $14,500,000, which is be re-determined semi-annually.  The Company is required to maintain certain covenants of which the Company was in compliance at December 31, 2002.  The Company expects to extend the maturity date of its revolving credit agreement to April 2005 and maintain the current collateral borrowing base of $14,500,000.

 

Aggregate maturities required on long-term debt at December 31, 2002 are due in future years as follows:

 

 

 

5.                      Commitments and Contingencies:

 

Lease Commitments —The Company leases office space in Oklahoma and certain vehicles under long-term operating leases. The Company’s leases include the cost of real property taxes and utilities. Insurance and routine maintenance are the Company’s responsibility.

 

F-17

 

Future minimum lease payments for all non-cancelable operating leases are as follows:

 

 

 

Rent expense was $180,491, $170,338 and $125,640 for the years ended December 31, 2002, 2001 and 2000, respectively.

 

Contingencies - On November 29, 2000 in the District Court of Tulsa County, State of Oklahoma, a Petition was filed by ONEOK Energy Marketing and Trading Company, L.P. (“ONEOK”), plaintiffs, naming the Company and two wholly-owned subsidiaries, Red River Field Services, L.L.C. and Red River Energy, L.L.C. (“Beta”), as defendants.  In the lawsuit, the plaintiff alleges that Beta discontinued selling gas to the plaintiff under a fixed price agreement and sold the gas instead to other suppliers.  Beta filed a counterclaim on January 24, 2001, alleging that the contract had been terminated pursuant to its terms for nonpayment by the plaintiff for gas supplied prior to termination, and seeking damages for the unpaid charges.

 

In 2002, the Company settled the above claim and counterclaim with ONEOK through independent mediation.  It was mutually agreed to release all claims and Beta paid ONEOK $43,000 in addition to the $282,096 of funds held by ONEOK.  Each party was responsible for their legal fees and costs associated with this matter of which Beta’s total legal fees were approximately $85,600.  Net of amounts due from joint interest partners, a non-recurring charge of $205,415 was recorded to income in the year ended December 31, 2001 related to the settlement.  In the fourth quarter of 2002, the Company reserved approximately $155,000 relative to the amount due from the joint interest owners involved and accordingly charged bad debt expense for such amount.  The Company is currently negotiating with the joint owners for settlement of the amount due to the Company.

 

In September 2001, the Company participated with a 62.5% interest in the drilling of the Dore #1, Live Oak Prospect located in Vermilion Parish, Louisiana.  The well, which was drilled by a third-party contract drilling company, was deemed non-commercial and plugged and abandoned.  During plugging operations, drilling fluid was discovered surfacing away from the well location indicating an integrity issue with the well bore.  All regulatory agencies were notified and the Company, as operator of the well, is conducting a groundwater investigation to determine the extent of groundwater contamination, if any.  The estimated cost for the investigation is approximately $365,000 and will be covered by the Company’s pollution insurance coverage.  If contamination were present, groundwater remediation would be necessary.  At this time, no contamination has been detected during the ongoing testing and no cost estimate for any groundwater remediation has been prepared at this time.

 

F-18

 

6.                      Derivative and Hedging Activities:

 

In accordance with the transition provisions of SFAS No. 133, on January 1, 2001, in connection with Beta’s hedging activities, the Company recorded as cumulative effect adjustments a loss of $953,488 (net of $635,488 income tax) in accumulated other comprehensive loss and a corresponding liability. Subsequent to January 1, 2001, the Company realized a loss of  $340,048 (net of $226,699 income tax) in the twelve month period ended December 31, 2001.

 

Natural Gas — During the twelve month period ending December 31, 2002, the Company had outstanding commodity price hedging contracts as set forth below with respect to its 2001 through 2003 natural gas production.  The hedging transactions are settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days of a particular contract month.

 

 

At December 31, 2002, the outstanding contracts had a negative fair market value of $559,024 and accordingly the Company recorded a derivative liability for such amount.  The fair market value is based on the NYMEX futures contract price for the outstanding contract months at December 31, 2002.  For the contracts settled during 2002 and 2001, the Company had realized losses of ($564,277), (no tax effect) and ($388,034), (net of income tax effect of $258,689), respectively.  The collar arrangements are costless and no net premium is received in cash or as a favorable rate.   The impact of the natural gas hedges reduced the Company’s average natural gas price received by $.25 per Mcf for 2002 and 2001.

 

Crude Oil — During the twelve-month period ending December 31, 2002, the Company had outstanding commodity price hedging contracts as set forth below with respect to its 2001 through 2003 crude oil production.  The hedging transactions are settled based upon the average of the reported daily settlement prices per barrel for West Texas Intermediate Light Sweet Crude Oil on the NYMEX for each trading day of a particular contract month.

 

 

 

F-19

 

At December 31, 2002, the outstanding contracts had a negative fair market value of $143,393.  The fair market value is based on the NYMEX-West Texas Intermediate futures contract price for the outstanding contract months at December 31, 2002 and accordingly the Company recorded a derivative liability for such amount.  For the contracts settled in 2002 and 2001, the Company realized a loss of ($219,297) in 2002 and realized a gain of $47,986 (net of income tax effect of $31,990) in 2001.  These contracts are costless and no net premium is received in cash or as a favorable rate.  The impact of the crude oil hedges decreased the Company’s average crude oil price received by $1.76 per Bbl in 2002 and increased the Company’s average crude oil price received by $.76 per Bbl in 2001.

 

7.                      Stockholders’ Equity:

 

Preferred Private Placement - On June 29, 2001 the Company completed its Private Placement Offering of Series A 8% Convertible Preferred Stock and common stock purchase warrants, offered as units of one Preferred Share and one-half of one Warrant at $9.25 per unit.  Net proceeds received from the Offering were approximately $5,041,528 net of estimated offering expenses, including brokers’ commissions and other fees and expenses of $547,862.  The Company issued

604,272 Preferred Shares and 302,136 Warrants to purchase a like number of shares of Beta’s common stock at a price equal to the Offering price or $9.25 per share.  Brokers were issued 59,775 non-callable warrants as part of their commission.  All investors participating in the Offering were accredited.  The proceeds were used by the Company to help meet its capital requirements, including drilling costs and for other corporate purposes.

 

The Preferred Shares may be converted by the holder at anytime at an exchange rate of one share of the Company’s common stock for each one Preferred Share converted.  The Preferred Shares will automatically convert into shares of the Company’s common stock on a one-share for one-share basis effective the first trading day after the reported high selling price for Beta’s common stock is at least 150% of the per Unit offering price of $9.25 per share or $13.875 per share for any 10 trading days.

 

The Preferred Shares pay quarterly cash dividends commencing in the quarter that the Preferred Shares are issued, at an annual rate of 8% per annum, simple interest.

 

The Company has the unilateral right to redeem all or any of the outstanding Preferred Shares from the date of issuance but must pay a premium if redeemed within the first five years.  The holders of the Preferred Shares will be entitled to a liquidation preference equal to the stated value of the Preferred Shares plus any unpaid and accrued dividends through the date of any liquidation or dissolution of the Company.  At December 31, 2002, the liquidation preference was approximately $5,702,097.  Warrants are non-transferable and may be exercised at any time through June 29, 2006.

 

F-20

 

Treasury Stock - On September 19, 2001 the Company’s Board of Directors authorized a stock repurchase program for up to an aggregate of $1,000,000 of the Company’s common stock to be effective from September 19, 2001 to January 19, 2002.  The authorization to repurchase shares was facilitated in part by an Order issued by the Securities and Exchange Commission on September 14, 2001.  The Order temporarily increased the flexibility with respect to certain SEC

rules pertaining to issuer stock repurchases. At December 31, 2001, the Company had reacquired 42,500 shares for a total cost of $198,920 or $4.68 per share.

 

In January 2002, the Company reissued 36,485 shares with a public market value of approximately $170,767 for geological and geophysical services associated with certain of its unevaluated properties.  At December 31, 2002, the Company held 6,015 treasury shares with a  market value of $5,173.

 

Subsequent to December 31, 2002, the Company’s Board of Directors authorized a stock repurchase program for up to an aggregate of 100,000 shares of the Company’s common stock. For further detail please refer to Note 12. SUBSEQUENT EVENTS.

 

Warrants/Options — Effective October 21, 2002, David A. Wilkins was appointed as the Company’s President and CEO and joined the Company’s Board of Directors.  As partial consideration for the forfeiture of his incentive common stock options (vested and unvested) with his former employer, Mr. Wilkins was granted an option to purchase 500,000 shares of the Company’s stock at an exercise price of $1.30 per share.  The Company also committed to grant to him on December 31, 2003 (if he is still employed at that time) an option to purchase 100,000 shares at a price equal to the Company’s common stock closing price on The NASDAQ Stock Market on that date. These options will have a term of ten years and vest over a three-year period from the date of grant, with one third (1/3) becoming exercisable on the first anniversary of the grant, one third (1/3) becoming exercisable on the second anniversary of the grant and the remaining one third (1/3) becoming exercisable on the third anniversary of the grant.

 

In 2001 and 2000 the Company issued 20,000 and 161,000 warrants respectively, to employees, as employment inducement, with exercise prices ranging from $7.50 - $9.00 per share.  The exercise prices were equal to or greater than the market price of the common stock on the grant date.  The warrants will vest over a three year period and will expire between 2005 and 2006.

 

During the year ended December 31, 2000, the Company issued 75,000 warrants with an exercise price of $7.75, of which 60,000 warrants were cancelled, in connection with an acquisition of unevaluated oil and gas properties.  The warrants were valued at $45,847 using the Black-Scholes valuation model with a volatility of 50.1%, risk free interest rate of 5.77% and an estimated time to expire of three years.  The warrants vest immediately and begin to expire in 2006.

 

F-21

 

The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants and options as of December 31, 2002:

 

 

The Company is entitled to call certain warrants at any time after the date that its common stock is traded on any exchange for a 10-day period at a target price, ranging from $7.00 through $10.00.  At December 31, 2002, 530,275 warrants were callable with a weighted average exercise price of $7.98 per share.  The remaining 1,358,723 warrants outstanding and 500,000 options outstanding are non-callable with a weighted average price of $7.13 per share for the warrants outstanding and a weighted average price of $1.30 per share for the options outstanding.

 

On December 30, 2002, the Company’s Board of Directors approved the extensions of the expiration dates of certain outstanding common stock purchase warrants with expiration dates ranging from December 30, 2002 through December 31, 2003.  The extensions were for an additional two years past the original expiration dates and affected 913,179 common stock purchase warrants. The affected warrants have exercise prices ranging from $3.75 per share to $7.50 per share.  The charge to the Company’s earnings was $14,842.

 

If not previously exercised, 554,496 warrants will expire in 2004, 935,587 warrants will expire in 2005, 383,915 warrants will expire in 2006 and 15,000 will expire in 2007.  500,000 options will expire in 2012.

 

Stock Option Plan - In August 2000, the Company adopted the 1999 Incentive and Nonstatutory Stock Option Plan (the 1999 plan) covering 700,000 shares that had previously been approved by the Board of Directors in August 1999.  The 1999 plan is a “dual plan” which provides for the grant of both incentive stock options and non-qualified stock options and was designed to attract and retain the services of employees, officers, directors, and consultants.  The price of the options granted pursuant to the plan shall not be less than 100% of the fair market value of the shares on the date of grant.  Prices for incentive options granted to employees who own 10% or more of the Company’s stock is at least 110% of market value at date of grant.   The plan will be administered by a compensation committee consisting of two or more disinterested non-employee board members who will decide the vesting period of the options, if any, and no option will be exercisable after ten years from the date granted.  The stock option plan will continue in effect for 10 years from August

 

F-22

 

20, 1999, unless sooner terminated by the Board of Directors.  Unless otherwise provided by the Board of Directors, the stock options granted under the stock option plan will terminate immediately prior to the consummation of a proposed dissolution or liquidation of the Company.

 

For the twelve months ending December 31, 2002, the Company granted 35,000 options with an exercise price of $3.30 per share to certain employees.  Of the 35,000 options, one-third (33.3%) of the options vested upon grant, the next one-third will vest on the first anniversary date of the grant and the remaining one-third will vest on the second anniversary date of the grant.  Outside directors were granted 100,000 options with the exercise prices ranging from $1.42 to $5.22 per share and vested immediately.  The exercise prices were based on 110% of market price of the common stock on the grant dates. All of the options issued in 2002 were for a term of five years and will expire in 2007.

 

During 2001, the Company granted 93,500 options to certain employees at an average exercise price of $4.60 per share, which was greater than or equal to the market price of the common stock on the grant date.  79,500 options vested immediately and the remaining will vest at various stages from 2001 through 2004.  All of the options will expire in 2006.  25,000 options were granted to an outside director with an exercise price of $8.45 per share, which was 110% of the market value of the common stock at the grant date, and vested immediately.  The options will expire in 2006.

 

In 2000, the Company granted options to purchase 186,000 shares of common stock to employees.  135,000 options were granted with an exercise price of $7.70 per share and 51,000 options were granted with an exercise price of $9.00 per share.  The exercise prices were greater than the market price on the dates of grant. 135,000 options vested immediately and the remaining 51,000 options vest over a three-year period.  The options begin to expire in 2004 and 2005.  Outside directors were granted 75,000 options with an average exercise price of $10.08 per share, which was 110% of the market value of the common stock on the grant date.  The options vested immediately and will expire in 2005.

 

During August 1999, the Company granted options to purchase 97,500 shares of common stock to employees under the 1999 plan.  The options did not become effective until the 1999 stock option plan was approved by the shareholders.  The options were granted with an exercise price of $6.00 which represented an amount in excess of 110% of the fair market value on the date of grant.  The options vested immediately and expire in 2009.

 

 

 

F-23

 

The following table sets forth activity for all options granted under the 1999 Plan:

 

 

 

 

At December 31, 2002, 499,667 options to purchase shares were exercisable at prices ranging from $1.42 to $10.25 per share.  The remaining 30,333 options outstanding will vest equally in 2003 and 2004 with exercise prices ranging from $3.30 per share to $9.00 per share.

 

If not previously exercised, the outstanding plan options will expire as follows:

 

 

As stated in Note 2, the Company has not adopted the fair value accounting prescribed by FASB123 for employees.  Had compensation cost for stock options issued to employees been determined based on the fair value at grant date for awards in 2002, 2001 and 2000 consistent with the provisions of

 

FASB123, the Company’s net income (loss) and net income (loss) per share would have been adjusted to the proforma amounts indicated below:

 

 

 

 

The fair value of each option and warrant granted to employees was estimated on the date of grant using the Black-Scholes option-pricing model using the following assumptions: risk-free interest rates ranging

 

F-24

 

from 1.47% to 1.84%, expected life of two to three years; dividend yield of 0%; and expected volatility ranging from 58.15% to 60.45%. The weighted-average fair value of the options on the grant date for the years ended December 31, 2002, 2001 and 2000 was $.63, $1.23 and $3.18 per share, respectively.

 

8.                      Income Taxes:

 

Income tax benefit (expense) for the indicated periods is comprised of the following:

 

 

The actual income tax benefit (expense) differs from the expected tax benefit (expense) as computed by applying the U.S. Federal corporate income tax rate of 34% for each period as follows:

 

 

 

 

 

F-25

 

The components of the net deferred tax asset and liability recognized are as follows:

 

 

 

 

At December 31, 2002, the Company had Federal net operating loss carry forwards of approximately $20,771,000 which expire in the years 2012 through 2022.

 

Utilization of the tax net operating loss carry-forwards may be limited in the event a 50% or more change in ownership occurs within a three-year period.

 

9.                      Other:

 

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.

 

In December 2002, Mr. Steve A. Antry, the Company’s former President and Chariman of the Board and a current Board member, notified us that he became a member in Grey Goose Resources, LLC.  Grey Goose Resources, LLC does not own any interests in our oil and gas properties.

 

Mr. Robert E. Davis, Jr., director, has overriding royalty interests in certain of our 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.

 

Employment Contracts - Effective October 21, 2002, Steve A. Antry resigned as the Company’s President and Chairman of the Board.  In settlement of Mr. Antry’s employment contract dated June 23, 1997, Mr. Antry received a severance payment equal to $150,000, which is his annual base salary, payable in twenty-four (24) equal semi-monthly installments commencing on November 15, 2002.  Additionally, the Company will pay for Mr. Antry’s family health insurance coverage for twelve (12) months or until October 21, 2003.  Mr. Antry’s contract provided for an indefinite term of employment at an annual salary of $150,000 commencing in October of 1997 and an annual car allowance of up to $12,000.

 

F-26

 

Effective October 21, 2002, David A. Wilkins was appointed as the Company’s President and CEO and joined the Company’s Board of Directors.  Mr. Wilkins compensation includes an annual base salary of  $160,000 and eligibility for 2003 incentive compensation equal to, and  not less than, 40% of his annual salary.  In consideration for the forfeiture of his incentive common stock options (vested and unvested) with his former employer, he will receive the following: 1.) a $50,000 bonus paid upon his commencement of employment, 2.) a $250,000 bonus payable on January 2, 2003, 3.) a $150,000 bonus payable on July 1, 2003 and 4.) a $150,000 bonus payable on January 2, 2004.  The bonuses require that the Company employ Mr. Wilkins at the respective bonus dates.  Mr. Wilkins was granted an option to purchase 500,000 shares of our stock at an exercise price of $1.30 per share.  The Company also committed to grant to him on December 31, 2003 (if he is still employed at that time) an option to purchase 100,000 shares at a price equal to the Company’s common stock closing price on The NASDAQ Stock Market on that date. These options will have a term of ten years and vest over a three-year period from the date of grant, with one third (1/3) becoming exercisable on the first anniversary of the grant, one third (1/3) becoming exercisable on the second anniversary of the grant and the remaining one third (1/3) becoming exercisable on the third anniversary of the grant.

 

Deferred Compensation - In 1998, the Company began to offer a simple individual retirement account (IRA) plan for all employees meeting certain eligibility requirements.  Employees may contribute up to 3% of the employee’s eligible compensation.  The Company’s contribution to the plan for the years ended December 31, 2002, 2001 and 2000 was $23,784, $31,377, and $15,456, respectively.

 

10.               Other Assets:

 

Other assets of approximately $76,208 and $1,472,570 at December 31, 2002 and December 31, 2001, respectively, consisted primarily of unapplied well prepayments.

 

F-27

 

11.               Net Income (Loss) per Common Share:

 

The following represents the calculation of net income (loss) per common share:

 

 

		2002			2001			2000
Basic
Net income (loss)		$	(6,881,612	)	$	(9,046,084	)	$	1,425,565
Less: preferred dividends		(447,151		)	(231,821		)	—
Net income (loss) applicable to common shareholders		$	(7,328,763	)	$	(9,277,905	)	$	1,425,565
Weighted average number of shares		12,417,957			12,368,373			10,616,692
Basic earnings (loss) per share		$	(.59	)	$	(.75	)	$	.13
Diluted
Net income (loss)		$	(7,328,763	)	$	(9,046,084	)	$	1,425,565
Plus: preferred dividends		—			—			—
Net income (loss) applicable to common shareholders		$	(7,328,763	)	$	(9,046,084	)	$	1,425,565
Weighted average number of shares		12,417,957			12,368,373			10,616,692
Common stock equivalent shares representing shares issuable upon exercise of stock options		Antidilutive			Antidilutive			24,646
Common stock equivalent shares representing shares issuable upon exercise of warrants		Antidilutive			Antidilutive			640,075
Common stock equivalent shares representing shares “as-if” conversion of preferred shares		Antidilutive			Antidilutive			—
Weighted average number of shares used in calculation of diluted income (loss) per share		12,417,957			12,368,373			11,281,413
Diluted earnings (loss) per share		$	(.59	)	$	(.75	)	$	.13

 

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

 

 

F-28

 

12.               Subsequent Events:

 

Subsequent to December 31, 2002, the Company adopted FASB Statement No. 123 Accounting for Stock-Based Compensation (FASB 123) and related interpretations in accounting for its employee and director stock options.  Under FASB Statement No. 148 Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment to FASB 123, certain transitional alternatives are available for a voluntary change to the fair value based method of accounting for stock-based employee compensation if adopted in a fiscal year beginning before December 16, 2002.  The Company will use the prospective method which will apply prospectively the fair value recognition method to all employee and director awards granted, modified or settled after the beginning of the fiscal year in which the fair value based method of accounting for stock-based compensation is adopted.

 

Effective January 16, 2003, the Company’s Board of Directors authorized a stock repurchase program for up to an aggregate of 100,000 shares of the Company’s common stock.  Purchases may be made in the open market, at prevailing market prices, or in privately negotiated transactions from time to time, and will depend on market conditions, business opportunities and other factors. Any purchases are expected to be made in compliance with the safe harbor provisions of Rule 10b-18 promulgated by the Securities and Exchange Commission under the Securities and Exchange Act of 1934.  To date the Company has purchased 6,800 shares for $5,312, or $.78 per share.

 

13.               Unaudited Supplementary Oil and Natural Gas Information:

 

The following supplementary information is presented in compliance with United States Securities and Exchange Commission (“SEC”) regulations and FASB Statement No. 69, “Disclosures About Oil and Gas Producing Activities,” and is not covered by the report of the Company’s independent auditors.

 

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.  Proved developed oil and gas reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods.  The reserve data is based on studies prepared by the Company’s independent consulting petroleum engineers.  Reserve estimates require substantial judgment on the part of petroleum engineers resulting in imprecise determinations, particularly with respect to new discoveries.  Accordingly, it is expected that the estimates of reserves will change as future production and development information become available.  At December 31, 2002, the Company’s proved oil and gas reserves are located in Oklahoma, Texas, Louisiana and Kansas.

 

The following table presents estimates of the Company’s net proved oil and gas reserves and changes therein for the years ended December 31, 2002, 2001 and 2000:

 

F-29

 

Changes in Quantities of Proved Petroleum and Natural Gas Reserves (unaudited)

 

 

 

 

 

Standardized Measure of Discounted Future Net Cash Flows (unaudited) - Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves.  The Company has followed these guidelines which are briefly discussed below.

 

Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced.  Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits.  The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

 

 

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company’s expectations for actual revenues to be derived from those reserves nor their present worth.  The limitations inherent in

 

F-30

 

the reserve quantity estimation process, as discussed previously are equally applicable to the standardized measure computations since those estimates are the basis for the valuation process.

 

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves as of December 31, 2002, 2001 and 2000 based on the standardized measure prescribed in Statement of Financial Accounting Standard No. 69:

 

		Year ended December 31,
		2002			2001			2000
Future cash inflows		$	89,041,960		$	79,924,007		$	204,303,798
Future costs—
Production		(28,564,665		)	(27,624,047		)	(28,592,624		)
Development		(1,042,310		)	(5,742,783		)	(1,123,359		)
Future net cash inflows before  income tax		59,434,985			46,557,177			174,587,815
Future income tax		—			—			(49,221,755		)
Future net cash flows		59,434,985			46,557,177			125,366,060
10% discount factor		(23,505,546		)	(15,262,165		)	(53,907,406		)
Future net cash flows		$	35,929,439		$	31,295,012		$	71,458,654

 

 

Changes in the Standardized Measure (unaudited) - - The following are the principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2002, 2001 and 2000:

 

		Year ended December 31,
		2002			2001			2000
Standardized measure, beginning of year		$	31,295,012		$	71,458,654		$	6,012,972
Sale of oil and gas produced, net of production costs		(5,775,336		)	(9,318,921		)	(6,668,446		)
Purchase of minerals in place		—			92,246			77,595,310
Sales of minerals-in-place		(60,574		)	(1,721,355		)	—
Extensions and discoveries		1,914,161			14,887,920			15,200,178
Changes in income taxes, net		—			32,978,576			(28,056,400		)
Changes in prices and costs		29,343,972			(74,018,682		)	21,485,597
Changes in development costs		4,303,387			(4,269,818		)	78,373
Accretion of discount		3,129,501			7,145,865			601,297
Revisions of estimates and other		(28,220,684		)	(5,939,473		)	(14,790,227		)
Standardized measure, end of year		$	35,929,439		$	31,295,012		$	71,458,654

 

F-31

 

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 on the 28th day of March, 2003.

 

	BETA OIL & GAS, INC.
Date: March 28, 2003	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 28, 2003
Robert E. Davis, Jr.		Board of Directors
/s/ David A. Wilkins		Chief Executive Officer		March 28, 2003
David A. Wilkins		and President
/s/ Joseph L. Burnett		Chief Financial Officer, Corporate		March 28, 2003
Joseph L. Burnett		Secretary and Principal Accounting Officer
/s/ Steve A. Antry		Director		March 28, 2003
Steve A. Antry
/s/ Joe C. Richardson, Jr.		Director		March 28, 2003
Joe Richardson Jr.
/s/ Robert C. Stone, Jr.		Director		March 28, 2003
Robert C. Stone, Jr.

 

39

 

CERTIFICATIONS

 

I, David A. Wilkins, certify that:

 

1.   I have reviewed this annual report on Form 10-K of Beta Oil & Gas, Inc.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Date: March 28, 2003
	/s/ David A. Wilkins
	David A. Wilkins
	Chief Executive Officer and President

 

40

 

CERTIFICATIONS

 

I, Joseph L. Burnett, certify that:

 

1.  I have reviewed this annual report on Form 10-K of Beta Oil & Gas, Inc.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Date: March 28, 2003
					/s/ Joseph L. Burnett
					Joseph L. Burnett
					Chief Financial Officer

 

41

 

INDEX TO EXHIBITS

 

EXHIBIT NUMBER		DESCRIPTION
3.1		Original Articles of Incorporation of Registrant incorporated by reference to Exhibit 3.1 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/ 001059324-98-000005.txt).
3.2		Amended and Restated Bylaws of the Registrant, Dated October 29, 1998, incorporated by reference to Exhibit 3.2 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/ edgar/data/1059324/0001059324-98-000005.txt).
3.3		Certificate of Amendment of Articles of Incorporation of the Registrant, dated August 28, 2000, incorporated by reference to Exhibit 3.1 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/ 0001021890-01-500087.txt)
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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.4		T.A.C. Resources Agreement, Dated January 21, 1998, incorporated by reference to Exhibit 10.4 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.5		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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.6		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 at ( http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.7		Stansbury Basin (Australia) Prospect Agreement, Dated February 1998, incorporated by reference to Exhibit 10.7 of Beta’s S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.9		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 at ( http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.14		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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/0001059324-98-000005.txt).
10.19		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 at ( http://www.sec.gov/ Archives/edgar/data/1059324/0001059324-99-000011.txt).
10.20		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 at ( http://www.sec.gov/ Archives/edgar/data/1059324/0001059324-99-000011.txt).
10.21		Cheniere Energy, Inc. Option Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.21 of Beta’s Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.22		Dyad-Australia, Inc. Agreement Dated January 25, 1999, incorporated by reference to Exhibit 10.22 of Beta’s Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/ Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.24		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 at

 

42

 

		( http://www.sec.gov/Archives/edgar/data/1059324/ 0001059324-00-000007.txt)
10.25		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 at   http://www.sec.gov/Archives/edgar/ data/1059324/0001059324-00-000007.txt)
10.27		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 at ( http://www.sec.gov/Archives/ edgar/ data/1059324/000105932400000042/0001059324-00-000052.txt).
10.29		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 at  (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
10.30		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 at  (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
10.31		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 at (http://www.sec.gov/Archives/edgar/data/ 1059324/000102189001500087/ 0001021890-01-500087.txt).
10.32		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 at (http://www.sec.gov/Archives/edgar/data/1059324/ 000102189001500087/0001021890-01-500087.txt).
10.33		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 at (http://www.sec.gov/Archives/edgar/ data/1059324/000102189001500087/0001021890-01-500087.txt).
10.34		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, 2001at (http://www.sec.gov/Archives/edgar/ data/1059324/000102189001500087/0001021890-01-500087.txt).
10.35		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 at (http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
10.36		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.
10.37		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 at ( http://www.sec.gov/Archives/edgar/data/ 1059324/000105932400000042/0001059324-00-000042-0001.htm).
10.38		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.
10.39		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.
10.40		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.
10.41		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.
21		List of Subsidiaries incorporated by reference to Exhibit 21 of Beta’s Form 10-K for the year 2000 filed  April 2, 2001 at (http://www.sec.gov/Archives/edgar/data/1059324/ 000102189001500087/0001021890-01-500087.txt).
23.2		Consent of Hein + Associates, LLP. dated March 27, 2003
23.3		Consent of Ryder Scott and Associates dated March 27, 2003
99.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

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99.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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