Note 5.          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, plaintiff alleges that Beta discontinued 
                       selling gas to plaintiff in breach of a fixed price agreement and sold the gas instead to other 
                       suppliers.  Beta 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 were seeking damages for the unpaid funds of $282,096.  

                       In the quarter ended March 31, 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 the Company's total 
                       legal fees were approximately $85,600. Net of amounts due from joint interest owners, a non-
                       recurring charge of $205,415 was recorded to income in the year ended December 31, 2001. 
                       However, the total net impact, including the impact of the non-recurring charge, was a favorable 
                       $60,000 in additional net gas revenues due to the Company's counterclaim. The Company has 
                       notified all joint interest owners of the recoupment, which is approximately $200,500, and is 

9

                        discussing a proposed recoupment plan with certain owners. Certain owners do not agree with the 
                        proposed recoupment plan and have made a counter-proposal for settlement. The Company is 
                        currently evaluating the proposal. At September 30, 2002, the Company had not established a 
                        reserve for any potential non-collection or recoupment from the joint interest owners.

                        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 cost for the investigation is estimated to be 
                        approximately $270,000 and will be covered by the Company's pollution insurance coverage. If 
                        contamination is present, groundwater remediation would be necessary. No cost estimates 
                        for such remediation have been prepared at this time.

Note 6.          DERIVATIVE INSTRUMENTS 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 $499,552 (net of $333,035 income tax) in the nine-month period ended 
                       September 30, 2001.

                        At September 30, 2002, the outstanding contracts had a negative fair market value of $747,787 
                        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 
                        September 30, 2002. For the contracts settled, the Company has realized a loss of ($128,783) 
                        and ($167,193) for the three and nine-month periods ended September 30, 2002, respectively. 
                        These contracts are costless and no net premium is received in cash or as a favorable rate.

Note 7.          SUBSEQUENT EVENTS

                      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 a 2003 bonus of 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 Mr. Wilkins be employed by the Company 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.

                      Effective October 21, 2002, Robert E. Davis, Jr. was named to a non-officer position of Chairman 
                      of the Board.

                      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, Mr. Antry will receive 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.

                     Effective October 21, 2002 R. T. Fetters resigned as the Company's Managing Director of 
                     Exploration and from his position on the Company's Board of Directors. Mr. Fetters will provide 
                     consulting services to the Company from the effective date of his resignation through December 31, 
                     2002. Mr. Fetters will receive $10,416.67 per month, which is based on Mr. Fetters base salary, for 
                     the period covered by his consulting arrangement.

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         All forward-looking statements contained in this report are based on assumptions believed to be reasonable.

          These forward-looking statements include statements regarding:

          We can give no assurance that such expectations and assumptions will prove to be correct. Reserve estimates of oil and gas properties are generally different from the quantities of oil and natural gas that are ultimately recovered or found. This is particularly true for estimates applied to exploratory prospects and new production. Additionally, any statements contained in this report regarding forward-looking statements are subject to various known and unknown risks, uncertainties and contingencies, many of which are beyond our control. These and other risks and uncertainties, which are described in more detail in our Annual Report on Form 10-K filed with the Securities and Exchange Commission, could cause actual results and developments to be materially different from those expressed or implied by any of these forward-looking statements. Such things may cause actual results, performance, achievements or expectations to differ materially from the anticipated results, performance, achievements or expectations.

          Due to global events and signs of a slowly improving economy, commodity prices have strengthened since the first quarter of 2002. However, the current natural gas storage level remains at a near-record high for this time of the year 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 pricing 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. Future natural gas drilling activity may increase but will be dependent on long-term price stability.

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          A company's liquidity is the amount of time expected to elapse until an asset can be converted to cash or conversely until a liability has to be paid. Liquidity is one indication of a company's ability to meet its obligations or commitments. Historically, our major sources of liquidity have come from internally generated cash flow from operations, funds generated from the exercise of warrants/options and proceeds from public and private stock offerings.

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

          Excluding any futures transaction hedge asset or liability for comparison purposes, our working capital was a surplus of $245,269 at September 30, 2002 compared to a surplus of $3,416,486 at September 30, 2001 and a deficit of ($172,058) at December 31, 2001. The significant decrease in our working capital and liquidity at September 30, 2002, when compared to September 30, 2001, was due to higher capital expenditures associated with our intensified drilling and lease acquisition activity principally occurring in the last half of 2001. Approximately $15.1 million was expended in our 2001 capital program and was funded from: 1.) cash flow from operations, 2.) funds received from our preferred stock private placement, and 3.) proceeds from the sale of certain evaluated and unevaluated oil and gas properties. Factors contributing to our lower working capital and liquidity position at September 30, 2002 were: 1.) lower than anticipated produc tion rates from our gulf coast and South Texas properties, 2.) a significant cost overrun of approximately $1.0 million (net to our 32% working interest), production delay and a lower-than-expected initial production rate associated with the Rubel #1, Sara White prospect located in Galveston County, Texas, 3.) higher operating expense of approximately $130,000 associated with unplanned weather-related repairs on certain Mid-Continent properties and 4.) no significant production additions from our exploration activity to date. At September 30, 2002, we had a futures derivative liability, associated with that portion of our future production volume currently hedged, of $967,128. The futures transaction hedge liability represents the potential unrealized reduction in our future oil and gas revenue based on the current outstanding derivative contracts. The estimate is based on the NYMEX natural gas and crude oil futures prices in effect at September 30, 2002 and may vary materially from month to month.

          Our principal source of short-term liquidity is from operating cash flow. Should natural gas and crude oil prices decrease materially, our current operating cash flow would decrease and further reduce our liquidity. During the nine months ended September 30, 2002, our cash flow from operations has been supplemented by the receipt of approximately $2.6 million from the sale of certain drill-ready prospects and non-core marginal producing properties. We received approximately $1.1 million in the third quarter of 2002 from such sales. The divestment of the non-core producing properties netted approximately $317,000 and had no significant impact on our proved reserves. Subsequent to September 30, 2002, we received an additional $650,000 related to the West Broussard agreement (For further information, please refer to (PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 2. OIL AND GAS PROPERTIES). We will continue to eva luate those properties that have low operating margins for possible divestment. Additionally, we will continue to review and optimize operating and general and administrative expenses.

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          Our borrowing base capacity under the current credit facility, which was acquired through the Red River Energy acquisition, is not a material source of capital. Historically we have not used credit facilities for a source of funds in our drilling or leasing activity. Should proved developed reserves not materially increase and/or pricing materially declines, our borrowing base may be reduced below the amount currently borrowed and outstanding under this facility. If this event occurs we would be obligated to pay down the outstanding amount to the re-determined borrowing capacity. We would rely on cash flow from operations and funds generated from the sale of unevaluated or proved undeveloped prospects to make this pay down. It is possible that we would have to sell some non-core assets as well in order to meet this obligation. In the second quarter of 2002, our borrowing base was re-determined and the current borrowing capacity is $14,500,00 0. Currently, a balance of $13,634,652 is outstanding against the borrowing base. The current credit agreement was extended by one year and has a maturity date of March 15, 2004. At September 30, 2002, our effective interest rate, which is LIBOR base rate plus 2.2%, was approximately 3.9%.

          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 current exploratory or development drilling activities, gas and oil price conditions and other related economic factors. The following tables show our contractual obligations and commitments as of September 30, 2002.

     (1)     $13,634,652 is related to our current credit agreement with a commercial bank.
     (2)     Represents amounts due under current operating lease agreements including the office rental agreement.

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

     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:

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     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.

     Derivative instruments and hedging activity - -- We use derivatives in a limited manner to protect against commodity price volatility. Effectively, we sell a portion of our natural gas and crude oil based on a NYMEX based price with a set floor (bottom) and ceiling (top) price or a range. Our derivatives are recorded on the balance sheet at fair value and changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of transaction. Our derivative contracts consist of cash flow hedge transactions which hedge the 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 fu ture natural gas and crude oil prices. However, the fluctuation in fair value will be offset by the future actual value received from the hedged volume.

     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, th at are "captive" to one purchaser due to the location of the production and lack of alternate sources of purchasers. In this particular instance, Duke Energy is the purchaser.

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Effects of Transactions With Related and Certain Other Parties
     During the nine months ended September 30, 2002, the Waveland Group, a non-affiliated entity, through various partnerships, has acquired an approximate 12% working interest in our West Broussard, Lafayette Parish, Louisiana prospect, a 12.5% working interest in our Lake Boeuf, Lafourche Parish, Louisiana prospect and a 10% working interest in our unevaluated shallow Brookshire Dome prospect area in Waller County, Texas on standard industry terms for both the acreage and participation in the subsequent drilling of the prospects. We received approximately $893,200 for the acreage and promote on the future drilling of the prospects' wells.

Plan of Operation for 2002
     For the nine months ended September 30, 2002, we expended approximately $4.6 million, primarily comprised of: 1) Approximately $1.1 million related to our Jackson County drilling, seismic and leasing activity, 2.) $1.3 million expended on the Rubel #1, Sara White prospect located in Galveston County, Texas, 3.) $1.0 million in the drilling, completion and land activity associated with our Brookshire Dome project located in Waller County Texas, 4.) $.3 million on additional activity in our West Broussard prospect, 5.) $.4 million expended on the recompletion and rework of our West Cameron Block 49 production and 6.) $.4 million for drilling, remedial and rework activity in the Mid-Continent area.

     To date, we have participated in the drilling of 20 gross wells, (3.80 net wells) of which 11 gross wells (2.50 net wells) were completed successfully as producers, seven gross wells (.93 net wells) were either dry holes or temporarily abandoned and three gross wells (.37 net well) are currently being completed.

     In Jackson County, we have participated in the drilling of four gross wells (.568 net wells) in 2002. The Long Beach #1, an 18,000 foot Wilcox test well which we participated with a 2% carried interest reached the objective depth and encountered the Wilcox sand but was deemed uneconomical. The well was plugged and abandoned. Additionally, the Elk Hills #1 Wilcox test, which commenced drilling in late 2001 was evaluated for considerable time before temporarily abandoning the well in the second quarter of 2002. In April 2002, we participated with a 25% working interest in the drilling of the Yaussi #1, a Yegua test well, which was unsuccessful and plugged. In the third quarter of 2002, we participated in the drilling of the Truckstop #1, a Yegua test well located in the same fault block tested by the Elk Hills #1. Results were initially encouraging but due to drilling problems the well had to be side-tracked and redrilled. Upon the redrill, the Yeuga sand was wet and the well was temporarily plugged and abandoned. We had a 6.25% interest in the well. Total cost incurred to date for Jackson County area is approximately $1.1million.

     The Rubel #1 (Sara White Prospect) located in Galveston County, Texas and operated by Ocean Energy was successfully completed in the "S" sand in the second quarter of 2002. A production test was performed and the well flowed 2.1 Mmcf per day of natural gas and 30 barrels per day of condensate. The well commenced sales in August 2002 after a considerable delay due to right-of-way issues regarding the sales line. However, initial production has been impaired by water encroachment and has significantly reduced the production rate. Currently, the well is producing 300 gross (77 net) Mcf of natural gas per day and 6 gross (2 net) barrels of condensate per day. The operator is evaluating the possibility of plugging back the current producing zone and completing other higher zones. We have a 32% working interest in the well and currently have a total cost in the well of approximately $2.7 million, which is approximately $1.0 million net to us over the originally authorized budget.

     In the Brookshire Dome project, for nine months ended September 30, 2002 we have participated in the drilling of 13 gross wells (2.59 net wells), of which eight gross wells (1.86 net wells) were successfully completed, two gross wells (.36 net well) were dry holes and three gross wells (.37 net well) are currently in the completion stage. Our current production from the Brookshire Dome area is 75 net barrels of oil per day and 135 net Mcf of natural gas per day. We are in the process of evaluating the ultimate reserve potential and decline rate associated with the shallow wells drilled since our activity began in the last half of 2001. We have experienced steeper than expected declines with the production and will farm out our interest or selectively participate in the immediate drilling activity until our evaluation is complete.

     In the second quarter of 2002, we participated in the drilling of two gross wells (.30 net wells) in McIntosh County, Oklahoma, both of which were successful. A Wilcox development well, is currently producing approximately 275 gross Mcf (28 net Mcf) of natural gas per day. A successful Arbuckle test well, which was successfully completed in the second

16

quarter, commenced sales early in the third quarter of 2002 and currently is producing 670 gross Mcf (95 net Mcf) of natural gas per day. Additionally, three wells in our coal bed methane project were fracture stimulated during the third quarter and we are evaluating the results.

     We estimate our capital expenditures for 2002 to be approximately $5 million versus our original forecast of $7 million. Due to the results of our various exploration projects, which were in progress at the end of 2001 and the first quarter 2002 and unplanned projects, we reduced and shifted our budget in the last half of 2002 to lower risk profile projects.

     The following events or results have occurred that changed the allocation, timing and amount of our originally forecasted second half 2002 capital expenditures:

          *     In Galveston County, Texas, the deep Vicksburg test well, the Northeast Hitchcock prospect, which was
                 originally forecast to drill in the fourth quarter of 2002 has been indefinitely postponed by the operator 
                 due to the results and cost overrun related to the Rubel #1, Sara White prospect.

          *     The Detroit prospect, located in Red River and Lamar Counties, Texas has not sold at this time. We had 
                 originally scheduled drilling in the last half of 2002. This prospect will not be drilled until it is sold 
                 and will not drill until 2003.

           *     The Toko Syncline prospect located in Australia was originally forecast to drill in the first half of 2002 
                   but the operator has not sold the remaining interests in this prospect. Should the operator be 
                   successful in placing the remaining interest, we would participate in the drilling of this prospect with 
                   a 6% carried interest.

          *     The estimated cost of the rework and recompletion on the West Cameron Block #49 properties, which 
                  were performed in the 3^rd quarter of 2002, is approximately $500,000 - $600,000 net to our interest. 
                  The recompletion was not projected to occur until 2003 and 2004.

          *     The drilling of the Lake Boeuf prospect located in Lafayette Parish, Louisiana which was originally 
                  scheduled to begin drilling early in the second half of 2002, is expected to drill late in 2002 or early 
                  2003. The operator is working on the drilling schedule at this time.

          *     The West Broussard prospect located in Lafayette Parish, Louisiana was originally scheduled to 
                  begin drilling early in the second half of 2002. Delays in selling the remaining portion of the prospect 
                  caused the delay in drilling. At this time we anticipate a late 2002 or early 2003 date to commence drilling.

     Based on our actual results for the nine months ended 2002, we project our cash flow from operations for 2002 to be approximately $3.7 million versus our original projection of $4.8 million. Our current projection is based on an average natural gas price of $3.11 Mcf (versus our original projection of $2.37 per Mcf) and $22.64 per barrel (versus an original projection of $18.88 per barrel). Additionally, we project our average net daily production to be approximately 8.3 Mmcfe per day for 2002 versus an original estimate of 10.0 Mmcfe per day. The downward production rate revision is due to lower than forecast production rates in the first half of 2002 from our Gulf production, a steeper natural decline rate with the Brookshire Dome project, a hook up delay and a lower-than-expected initial production rate from the Rubel #1 and the delay of potential incremental production from our West Broussard and Lake Boeuf prospects which were originally scheduled to drill in th e third quarter of 2002 and go on line in the fourth quarter. The drilling of these prospects may commence in the fourth quarter of 2002 but they will not contribute to our cashflow in 2002. We do anticipate that our efforts from exploitation and remedial projects associated with our Mid-Continent assets may partially offset the shortfalls previously discussed.

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     For the remainder of 2002, we expect to fund our capital requirements from net cash flow from operations (after general and administrative expense) and proceeds received from the sale of certain drill-ready prospects and possibly other non-core properties. As with any projection, the timing and amounts for capital expenditures may 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. Additionally, lower natural gas and crude oil prices could adversely impact our ability to sell prospects. If this happens, it may be necessary for us to raise additional funds.

     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:

      Should our future projected capital expenditures be reduced by lower sources of cash flow or additional cash is required for reduction of our credit facility, our potential growth rate from our exploration activity 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.

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     Our long-term goal is to build the Company's asset base in an aggressive but efficient manner with a strong emphasis on operations. Before we can build, we must focus on our base, which will set the foundation for our future growth. Our immediate goal is to "optimize" our existing assets both from a production and technical perspective. Our emphasis is to create shareholder value by using a strong technical team to grow the Company through development of our existing asset base as well as looking for new opportunities via acquisitions and/or drilling. 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.

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We had a reported net loss of ($377,566) for the quarter ended September 30, 2002 compared to a net loss of ($4,657,047) for the same period ended 2001. The results of operations for the quarter ended September 30, 2001 included a $6,770,110 ($4,577,837 net of income tax) full cost ceiling impairment. There was no comparable adjustment for the quarter ended September 30, 2002. When comparing our results of operations for the three months ended September 30, 2002 to the same period ended 2001, excluding the impact of the full cost ceiling impairment, we had a reported net loss of ($377,566) compared to a net loss of ($79,210). Lower natural gas and crude oil prices and higher depletion expense primarily contributed to the increase in net loss for the period ended 2002.

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

     For the quarter ended September 30, 2002, oil and gas sales decreased $160,249 or 7%, from the same quarter ended 2001, to $2,238,435. The decrease resulted from lower natural gas and crude oil prices offset slightly by an increase in natural gas production. The lower commodity prices resulted in a decrease in revenue of approximately $179,957. Lower natural gas prices comprised 60% of the decrease with lower crude oil prices accounting for the remaining 40%. Our overall production volume was essentially flat for the quarter ended September 30, 2002 when compared to the same quarter ended in 2001.

     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 55% of our production on an equivalent Mmbtu basis for the quarter ended September 30, 2002. Based on our natural gas production for the three months ended September 30, 2002, a decline in the average natural gas price realized by Beta of $1.00 per Mcf would have resulted in an approximate $.5 million reduction in net income before income taxes. For the quarter ended September 30, 2002, the average sales price received for our natural gas was reduced by approximately $.22 per Mcf from our gas hedges and the average sales price received for our crude oil was reduced by approximately $4.07 per barrel from our crude oil hedges.

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     Operating expenses, excluding production and ad valorem taxes, increased $15,714 or 2%, to $711,092 for the quarter ended September 30, 2002 compared to the same period for 2001. The slight increase was due to our increased Brookshire Dome activity, which commenced in the last half of 2001.

     General and administrative expense for the three months ended September 30, 2002 decreased approximately $157,612 or 26%, to $453,617 compared to $611,229 for the same period in 2001. The decrease was due primarily to a reduction in personnel costs, insurance expense and contract accounting services. On July 1, 2002, we moved our operational accounting function "in-house", which had been outsourced prior to this date.

     Depletion and depreciation expense increased $228,267, or 24%, from the same period in 2001 to $1,190,460 for the three months ended September 30, 2002. Higher depletion expense associated with evaluated oil and gas properties accounted for the increase. The increase was due to a reduction in the estimated remaining reserves for the Rubel #1 and certain proved undeveloped locations in the Lapeyrousse, Louisiana area. The estimated remaining reserves for the Rubel #1 were revised due to the lower-than-expected initial production rate. The Lapeyrousse proved undeveloped reserves were lowered due to a dilution of our present working interest from additional leasing activity in this area in which we elected not to participate. The total downward revision was approximately 1.8 equivalent Bcf. Depletion expense per McfE for the three months ended September 30, 2002 was $1.54 per McfE compared to $1.21 per McfE for the same period in 2001. Depreciation expense related to other assets decreased $24,592 from the same period in 2001 to $47,645 for the three months ended September 30, 2002. 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 quarter ended September 30, 2002 resulted in lower depreciation expense for the period.

     There was no impairment expense for the quarter ended September 30, 2002. For the quarter ended September 30, 2001, an impairment write down of $6,770,110 was recorded to our full cost pool. The write down was mainly due to a significant decline in natural gas prices in the third quarter of 2001.

      Interest expense decreased for three months ended September 30, 2002, compared to the same period 2001, as a result of lower interest rates.

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

     For the nine months ended September 30, 2002, oil and gas sales decreased $3,330,134, or 32%, from the same nine-month period ended 2001, to $6,932,874. The decrease was a result of lower natural gas and crude oil prices for the nine months ended September 30, 2002. Lower natural gas prices comprised 85% of the decrease with lower crude oil prices accounting for the remaining 15%. Natural gas sales volumes were lower for the nine months ended September 30, 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 new production from the T. Cenac #1 well, located in the Lapeyrouse field, Terrebonne Parish, Louisiana. The lower production was due to greater than expected decline in the South Texas wells in the last half of 2001 and water production in the West Cameron Block 49 wells, which were reworked and back on line late in the third quarter. However, our crude oil sales volumes increased for the nine-month period ended 2002 when compared to the same period ended 2001 due to new production associated with our exploration activity in the Brookshire Dome area

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in Waller County, Texas and the T. Cenac #1. Our increase in crude oil production offset the decrease in natural gas production for the nine month period ended September 30, 2002.

     Hedges covered approximately 50% of our production on an equivalent Mmbtu basis for the nine months ended September 30, 2002. For the nine months ended September 30, 2002, the average sales price received for our natural gas was reduced by approximately $.10 per Mcf from our gas hedges and the average sales price received for our crude oil was reduced by approximately $1.25 per barrel from our crude oil hedges.

     Operating expenses, excluding production taxes, increased $329,868 or 19%, to $2,066,486 for the nine months ended September 30, 2002 compared to the same period for 2001. The increase was due to approximately $130,000 weather related repairs on our WEHLU property located in Oklahoma and the Peace Creek and R. E. Estey Units in Kansas. Additionally, we had an increase in operating expense of approximately $203,000 related to our Brookshire Dome, Waller County, Texas properties, in which activity commenced in the last half of 2001.

     Production taxes for the nine months ended September 30, 2002 decreased $239,984 when compared to the same period ended in 2001 due to a lower crude oil and natural gas revenues in 2002.

     General and administrative expenses for the nine months ended September 30, 2002 decreased approximately $477,676 or 26%, to $1,386,575 compared to $1,864,251 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.

     Depletion and depreciation expense decreased $283,264, or 8%, from the same period in 2001 to $3,495,126 for the nine months ended September 30, 2002. Depletion expense associated with evaluated oil and gas properties comprised $177,297 of the decrease. The decrease was due to a lower net evaluated cost basis for our evaluated properties for the nine-month period ended September 30, 2002 when compared to the same period for 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. In the third and fourth quarters of 2001, our full cost pool exceeded the full cost ceiling and accordingly we impaired, or wrote-down, our evaluated oil and gas properties by approximately $13.8 million. Lower natural gas and crude oil prices in the last half of 2001 contributed mainly to the lower ceiling. Depletion expense per McfE for the nine months ended September 30, 2002 was $1.44 per McfE compared to $1.52 per McfE for the same period in 2001. Depreciation expense related to other assets decreased $105,967 from the same period in 2001 to $160,340 for the nine months ended September 30, 2002. 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 nine month s ended September 30, 2002 resulted in lower depreciation expense for the period.

     Interest expense decreased for nine months ended September 30, 2002, compared to the same period 2001, as a result of lower interest rates.

     We are exposed to market risk related to adverse changes in oil and gas prices. Our oil and gas revenues can be significantly affected by volatile oil and gas prices. This volatility can be mitigated through the use of oil and gas derivative financial hedging instruments. Based on the average production rate for the nine months ended September 30, 2002, we have approximately 58% of our future natural gas production hedged through February 2003 and approximately 15% hedged for the period March 2003 through August 2003. We have approximately 44% of our future crude oil production hedged through March 2003 and approximately 22% hedged for the period April 2003 through September 2003. We use costless collars to hedge our production (For further information, please refer to PART I. FINANCIAL INFORMATION, Item 1. Financial Statements, Note 6. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES). The counterparty to our hedging agreements is a commercial bank. The r emainder of our production is not hedged and we may continue to experience wide fluctuations in oil and gas revenues as a result. We are also exposed to market risk related to adverse changes in interest rates. Our outstanding debt under our current credit facility bears interest at a LIBOR based rate plus 2.20%. Volatility in the future could be mitigated through the use of financial derivative instruments. Currently, we do not have any derivative financial instruments in place to mitigate this potential risk.

     With the participation of management, the Company's chief executive officer and chief financial officer evaluated the Company's disclosure controls and procedures on November 5, 2002. Based on this evaluation, the chief executive officer and the chief financial officer concluded that the disclosure controls and procedures are effective in connection with Company's filing of its quarterly report on Form 10-Q for the quarter ended September 30, 2002. Subsequent to November 5, 2002 through the date of this filing of Form 10-Q for the quarter ended September 30, 2002, there have been no significant changes in the Company's internal controls or in other factors that could significantly affect these controls, including any significant deficiencies or material weaknesses of internal controls that would require corrective action.

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 Item 5.    Other Information

     (a)     Exhibit No.        DESCRIPTION

                99.1                   Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as
                                          adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

     (b)     Form 8-K dated October 1, 2002 and filed October 2, 2002 reported the appointment of Mr. David A. Wilkins as President and Chief Executive Officer under Item 5.

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Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned who is duly authorized.

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

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

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

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

               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

Date: November 14, 2002

                                                                             /s/ David A. Wilkins         
                                                                         David A. Wilkins
                                                                         Chief Executive Officer

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Date: November 14, 2002

                                                                             /s/ Joseph L. Burnett         
                                                                         Joseph L. Burnett
                                                                         Chief Financial Officer

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