Item 1. Business of Beta 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, 2001, we owned interests in approximately 318 gross wells, 187 wells net to our interest, in the Mid-Continent, Texas and Louisiana regions and participated in the drilling and completion of 49 gross wells (11.57 net wells) for the year. Additionally, we own interests in 31,000 net acres in Kansas, Louisiana, Oklahoma, Texas and Wyoming plus a minority interest in a West Queensland, Australia concession.
At December 31, our oil and gas properties had net proved reserves of 29.7 BcfE, comprised of 24.7 Bcf of natural gas and 836.8 MBbl of oil. From the first quarter of 1999 through the fourth quarter of 2001, we have increased our average net daily production from 205 McfE of natural gas to 9,866 McfE of natural gas. For 2001, our production increased approximately 13% from a net daily production of approximately 8,730 McfE at the end of 2000.
Business Strategy Our overall goal is to maximize Beta's value through profitable growth in our oil and gas reserves. We feel this can be achieved through the exploration and development of our existing prospect inventory base located in the Gulf Coast regions of Texas and Louisiana. As with any dynamic environment, we must be flexible and adaptive to current economic and sector conditions in executing our growth plan. In 2002, we will supplement our exploration and development program with an acquisition program targeting properties that we believe possess high development potential.
Following the 2000 acquisition of Red River Energy, LLC, we have a base production level in place that can provide consistent cash flow to assist in funding our exploration efforts. Exploration and development activities have higher associated risks than those associated with acquisitions of producing properties. Two of the largest risks associated with exploration and development activities are:
o geological risks (the subject property does not hold recoverable oil or natural gas); o and project cost overruns.
By utilizing a "portfolio" approach in our exploration activities, we expect to minimize the overall effect of these risks. We thus participate in a larger number of exploratory and development activities by diversifying our ownership positions. We utilize available advanced technology, such as 3-dimensional ("3-D") seismic modeling to further reduce risk and enhance our success rates.
We believe that the availability of economical 3-D seismic surveys fundamentally changed the risk profile of oil and gas exploration in certain regions, specifically South Texas and Louisiana. Recognizing this, we have aggressively sought to acquire significant acreage blocks in selected areas for targeted, proprietary, 3-D seismic surveys. Using the data generated by initial proprietary seismic surveys, covering over 300 square miles, we have identified in excess of 200 potential drillsites net of 2001 activity. In general, when it is not geographically advantageous for us to be the operator, we rely on agreements with qualified operating oil and gas companies to operate many of our projects through the exploratory and production phases.
Current Projects
TEXAS Jackson County Approximately $18.2 million has been expended since our inception in lease acquisition, seismic and drilling activity in the onshore Jackson County, Texas Gulf Coast region. Parallel Petroleum Corporation, Allegro Investments, Inc. and Sue Ann Production, Inc operate the majority of our interests in the Jackson County properties. Drilling commenced on these prospects during 1999 and has resulted in a total of 28 (3.89 net) discoveries out of 41 (6.58 net) wells drilled for a 68% (.59% net) success rate. During the year 2001, 14 exploratory wells, (which resulted in 11 discoveries) and five development wells were drilled. The leasing of acreage covering 12 deeper Wilcox prospects generated by Beta was completed and drilling of two of those prospects commenced in 2001.
Frio/Yegua/Wilcox Trend 3-D Seismic Joint Venture, Jackson County, Texas The Frio/Yegua/Wilcox Trend, onshore in South Texas, is our initial cornerstone exploration area. Most of the positionn we acquired had never been explored with the benefits of advanced 3-D seismic and other current exploration, completion and production technologies.
In July 1997 Beta and various industry partners began assembling a 300+ square mile area in the heart of the Frio/Yegua/Wilcox trend, located in Jackson County, Texas on which to conduct an advanced 3-D seismic survey. The survey was conducted and, based on our review of the data approximately 44,000 acres remain under lease for drilling.
From the 3-D seismic survey data, we identified over 200 prospective drilling locations. Drilling commenced on this acreage in late 1999. Wells in this prospect are usually placed on-line within a few weeks of completion and have relatively low monthly operating expenses, thereby maximizing cash flow.
In early 2000, we engaged an independent reservoir evaluation firm to review our existing seismic data and drilling results in the Frio/Yegua/Wilcox trend in a 600 square mile area that encompasses Beta's acreage within this trend. Since 1997, 152 wells had been drilled in the area by other parties with over an 80% success rate. Of particular interest to us was that, over 40 of these wells were drilled to the deep Yegua and Wilcox sands between 13,000 and 18,000 feet with 87% successfully completed as producing wells. Some Wilcox fields in the trend have produced in excess of one TCF (trillion cubic feet) of natural gas. We identified 12 Wilcox prospects in the trend and commenced drilling those prospects in the latter half of 2001. For 2001, we participated in the drilling of: (1) five gross Yegua wells (.625 net wells), of which three were dry holes and two were completed in the shallower Frio sands, and (2) two gross Wilcox wells (.14 net wells). One was a dry hold and one was completed and producing in the Yegua formation. We had or will have an average 20% or less working interest in these prospects and will not be the operator.
We presently own working interests in four Onshore Gulf Coast exploration projects located in Jackson County, Texas. Approximately 47,892 gross acres, approximately 11,110 net acres, of oil and gas leases have been acquired in these four projects as of December 31, 2001. The operators completed 3-D seismic surveys over an area totaling 286 square miles within which these projects are located and continue to evaluate seismic data to select additional drilling locations.
Geological and Economic Overview of the Frio/Yegua/Wilcox Trend 3-D Joint Venture The subject lands for the projects lie in close proximity to productive oil and gas fields which produce from the Frio/Yegua/Wilcox intervals. We emphasize that the historical production results in areas near these prospects are not necessarily indicative of results that we may obtain from our oil and gas prospects.
Within the four project areas, there are high potential exploration opportunities that are being defined with the use of 3-D seismic. The Jackson County, Texas area has proven to be suitable for 3-D seismic as faulting and structures are easily identified and many stratigraphic reservoirs exhibit hydrocarbon indicators from the shallowest Miocene sands, throughout the Frio, and into the Vicksburg, Yegua, and Wilcox intervals. The Formosa Grande Prospect Area has numerous regional down-to-the-coast faults that are easily identified at the top of the Frio, but also has deep-seated faulting that does not exhibit displacement at the shallower horizons. Very often, these deep faults do create hydrocarbon traps. Most nearby producing fields in this trend area exhibit multiple stacked reservoirs.
A Frio level structure map exhibits numerous large four-way closures, primarily down-thrown to regional growth faulting. These large structures have, for the most part, been exploited, some as early as the 1930s and 1940s. Although it is not readily apparent in regional mapping, much of the Frio production is stratigraphic in nature, that is, trapped in channel sands that traverse structures, or in sands that "pinch out" up onto the flanks of these large structures. Significant reserves may remain in similar traps, which have not been developed to date. Such traps should be readily defined with 3-D seismic data.
Our project areas appear to be located in a suitable "trend" area for 3-D seismic technology to identify reserves that have been passed over in existing fields as well as to discover new reserves in deeper pools and untested fault segments in compartmentalized fields.
We believe this to be one of the best trends in the onshore Gulf Coast, and recognize the potential benefit of this largeacreage position available for a proprietary 3-D seismic survey. Given the drilling success rates in this trend, we would find it more difficult to acquire our interest in the area today. We believe this project provides somewhat lower risk, yet potentially highly rewarding drilling for several years, as well as many high impact, deeper projects.
Project Areas The following projects in which we are participating will use the same seismic techniques that the joint development group has previously used to identify potential drill sites. Currently, our net daily average production for the Jackson County wells is approximately 1,583 McfE of natural gas or 16% of our current production. The status of each project is as follows:
a.) Texana Project. Approximately 25,000 gross acres under seismic coverage; 13,520 gross acres under lease; 3,042 acres under lease net to Beta's 22.5 % working interest as of December 31, 2001: Approximately 40 square miles of 3-D seismic data has been acquired and processed. "Amplitude Versus Offset" analysis and data interpretation has been completed. Approximately 20 potential locations, 15 Frio/Yegua and eight Wilcox, have been identified for drilling in future periods. Drilling commenced in late 2000 with the first Yegua exploratory well completed successfully in the Frio sands due to lack of a commercial Yegua reservoir. The second exploratory well, the Elk Hills #1, is a Wilcox prospect and commenced drilling in the fourth quarter of 2001. Testing of the Wilcox formation is underway currently.
In 2001, we exchanged 2.5% in our Texana project for 2.5% in the Hilje project located in Wharton County, Texas immediately to the east of Jackson County. The interest was acquired from a third party working interest owner in the Hilje area. We participated in the drilling of one well, the Marek #1, which targeted the Wilcox sands. The well, which was operated by Pure Oil, was deemed to be non-commercial.
b.) Formosa Grande Project. Approximately 92,000 gross acres under seismic coverage; 3,932 gross acres under lease; 983 net acres under lease net to Beta's 25% working interest at December 31, 2001: Approximately 140 square miles of 3-D seismic data has been acquired. The seismic data has been interpreted and prospects identified. Approximately 66 potential locations, 64 Frio and two Miocene, have been identified for drilling in future periods.
Six (1.5 net) shallow middle Frio exploratory wells were drilled in 2001, two (.5 net) were discoveries and four (1.0 net) were dry holes. The two discoveries are collectively producing approximately 230 gross, (10 net), Mcf per day.
c.) Ganado Project. Approximately 25,000 gross acres under seismic coverage, 350 gross acres under lease; 71 acres under lease net to Beta's 20% working interest at December 31, 2001: Approximately 40 square miles of 3-D seismic data has been acquired and is in the interpretive stages. Approxi-mately 37 additional locations, 36 Frio/Vicksburg/Miocene and one Wilcox, have been identified for drilling in future periods.
Drilling in this project commenced in mid-1999 and has resulted in four (.8 net) discoveries and two (.4 net) dry holes. In 2001, one (.2 net) development well was successfully drilled and completed. Two (0 net) wells commenced drilling the fourth quarter, in which we elected not to participate due to project economics compared to other opportunities available. The two wells are currently in the completion process.
d.) BWC Project. Approximately 42,440 gross acres under seismic coverage, 16,610 gross acres under lease; 2,076 acres under lease net to Beta's 12.5% working interest at December 31, 2001: Approximately 66 square miles of 3-D seismic data has been acquired and is in the interpretive stage. Nine wells, three Yegua and five Frio exploratory wells and one Frio development well, were drilled in 2001. The three Yegua wells were unsuccessful but one was successfully completed in the Frio sand. Three of the five Frio exploratory wells were successful. The BWC discovery wells drilled in 2001 are currently producing an average of 1,230 gross (155.1 net) Mcf of natural gas per day.
Approximately 110 prospects, 103 Frio/Yegua and seven Wilcox/Queen City, in total have been identified for future drilling in this project. However, we believe that within this 300-square mile proprietary 3-D survey, it is the drilling in the deeper Wilcox formation that will have the greatest impact for us.
e.) Mexican Sweetheart Project. 1,381 gross acres under lease; 497 acres under lease net to Beta's 36% working interest at December 31, 2000: 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 would not maintain an interest greater than 12.5% in this project. The drilling of this well is projected for late 2002.
f.) Big Twelve Project. 8,758 gross acres under lease; 1,095 acres under lease net to Beta's 12.5% working interest at December 31, 2000: In 2001, we acquired a 12.5% interest in this project for $250,000 which flanks our Mexican Sweetheart project to the north and our Texana project to the west. A 19,000 Wilcox exploratory well was drilled in the last half of 2001. The well did encounter Wilcox sands but it was evaluated as non-commercial. However, it did prove up the Yegua formation and was successfully completed. The well went on line in 1/2002 and is currently producing 1,400 gross (89 net) Mcf per day.
Terms of Participation (Does not apply to Mexican Sweetheart) All of the lands covered by the exploration agreements are subject to provisions under which the parties each agree to offer a portion of any interests within "areas of mutual interest" near the property being acquired or explored to other parties to the agreement. The exploration agreements generally also provide, among other things, for Beta and others in each project to participate on the following terms and conditions:
Participants were required to pay 133% of the operator's actual cost of initial land costs, consisting mainly of seismic options, and the costs of acquiring, processing and interpreting seismic data. The 33% premium was paid to unrelated parties as compensation for assembling the leases and conducting the seismic operations. All costs incurred after the interpretation phase are billed to the participants at actual cost, based on their working interest ownership. The post- interpretation costs include the costs of acquiring leases, and the cost of drilling, completing and equipping wells. Most of the projects are now in the post-interpretive stage, however, data may be reprocessed to aid in interpretation.
Once the seismic data has been acquired and interpreted, prospects are identified and designated within the seismic survey areas. The parties to the agreement then have the option to participate in the prospect according to their pro-rata working interest. Those parties who elect not to participate forfeit their rights of participation in the specific prospect but retain the right to participate in other prospects proposed in the seismic survey area which are outside of the specific prospect (excluding BWC project).
Those parties who elect to participate in a specific prospect then proceed to acquire oil and gas leases within the prospect, usually by exercising seismic options or leasing the desired properties. The seismic options were acquired in advance of seismic acquisition and convey the right to conduct seismic operations as well as the option to enter into an oil and gas lease on the subject lands at a pre-determined price per acre with pre-established terms allowing extension of the lease for various terms by payment of annual rentals. The seismic option allows us, including our partners, to acquire and evaluate seismic data before actually acquiring leases. After the seismic data has been evaluated, Beta and its partners can then selectively acquire leases by exercising on acreage that is determined to be prospective from seismic evaluation. Seismic options covering lands, which are determined not to have oil and gas potential, are allowed to expire at no further cost to the participants. The cost of a seismic option is usually much lower than the cost of acquiring a lease and it also prevents the mineral owner lessor from leasing the oil and gas rights to another party during the term of the option.
Waller County The Brookshire Dome Project We have a joint exploration agreement with Revere Corporation (formerly with Prime Natural Resources) to explore and exploit oil and gas potential associated with the Brookshire Shallow Piercement Salt Dome located
approximately 30 miles west of Houston, Texas. In 2001, we increased our working interest from 25% to 40% in the majority of our present Brookshire position. We acquired an incremental 15% working interest in two producing properties and certain leasehold acreage for a total cost of $579,000. Additionally we acquired an additional working interest of 11.71% in three wells that were offsetting our current Brookshire position for approximately $272,500. These purchases were partially funded with proceeds from the sale of non-operating working interests in non-strategic gas properties located in West Texas. For further discussion, please see Item 8. Financial Statements, Note 2. Acquisitions And Dispositions of Oil And Gas Operations.
This salt dome had been considered barren of economic reserves due to an interpreted late growth history of the salt dome structure. In conjunction with existing seismic data shot in 1982, which was recently reprocessed with state of the art technology suggesting the possibility of sediments at depths of 4,000' to 7,000' below a salt overhang, additional seismic was shot in late 2001 and is currently in the final stages of processing.
Additional high technology interpretation of gravity data in conjunction with the seismic and a surface geochemical survey further supports this concept. Concurrent with this leasing activity, a series of successful shallow oil wells were drilled and completed south of our acreage block. This production from 2,500' to 3,000' in Miocene aged sands above the salt is out of trend and given the immaturity of the associated source rocks is considered by us to be re-migrated from deeper reservoirs, probably up faults from beneath the salt. These wells produce from 50 to 300 barrels of oil per day.
We have leased approximately 3,613 gross acres, 1,451 net acres, which are favorably located to test sands that may lie in a hydrocarbon trapping position below the salt. In the last half of 2001, an aggressive drilling program was undertaken to further test the shallow sands potential. In 2001, we drilled 16 gross Miocene wells, nine exploratory and seven development wells. Of the exploratory wells, we had six discoveries and three dry holes. Since 2000, we have expended approximately $3.4 million on lease acquisition, geological and geophysical and drilling of wells. The current daily production from our Brookshire Dome area is approximately 817 gross (183 net) gross barrels of oil and and 600 gross (180 net) Mcf. Drilling will re-commence in March 2002 with the aid of the new seismic data.
Galveston County The Greens Lake Project The Greens Lake Prospect area, which lies in the Transition Zone of Texas covering the shoreline and near shore environments in the Gulf of Mexico region, is located approximately one mile southeast of the town site of Hitchcock in Galveston County, Texas between Houston and the City of Galveston. Our working interest is 34% and Ocean Energy, Inc. is the operator.
Two separate west and northwest dipping upthrown fault closed structures have been delineated on the 5,500-acre lease block using downhole well control and a 24 square-mile proprietary 3-D seismic shoot. Prospective sands range in age from Miocene, Lower Frio, and Vicksburg. These two plays are actually deeper sand structural test extensions of the prolific Big Gas Sand producing fields of Sara White and North East Hitchcock and will be drilled to approximately 14,000 feet. Three prospects have been delineated within this project area, the Sara White Prospect (to the south), the N.E. Hitchcock Prospect (to the north), and a deep Vicksburg structure on trend with the one-half TCF Eagle Point field 10 miles to the northeast.
The Rubel #1 (Sara White Prospect), an apparent discovery, was spudded in November 2001and is currently in the completion stage. Third party log analysis recognizes 192 feet of net gas pay mostly concentrated in four pay sands. Further evaluation is ongoing.
Red River and Lamar Counties The Detroit Project The Detroit project, covering 15,000 acres, is under lease in Red River and Lamar Counties, Texas. The project was developed as a rework of existing seismic and an extensive radiometric survey of the entire area for surface detection of hydrocarbons. This large structural closure meets all the criteria for a major reserve accumulation from the Arbuckle Group. The Arbuckle is overlaid by a duplex structure involving the Jack Fork and Stanley formations similar to the Potato Hills field in Oklahoma. To date we have expended approximately $942,000 for acreage, seismic and other geological and geophysical costs. We have a 75% working interest in this prospect but will reduce our interest position to recover some or all of our acreage cost and partially fund our share of drilling cost. We plan to retain a 12.5% working interest.
LOUISIANA Beta has invested approximately $12.8 million in leases, seismic data collection and drilling in Louisiana. Drilling commenced on these prospects in 1998 and has resulted in six oil and gas discoveries so far. At present our net daily average production in the transition area of Louisiana is approximately 1,035 McfE of natural gas.
In 2001, we participated in the drilling of three wells in the south Louisiana area. The first well, the T.Cenac #1 located in Terrebonne Parish, was completed in the Duval sand and went on line in September 2001 and is currently producing approximately 8,000 gross Mcf (934 net Mcf) of natural gas per day and 140 gross barrels (15 net barrels) of condensate per day. The total cost expended for the drilling and acreage was approximately $1.3 million. We have an approximate 16.2% working interest in this area. The second well, the Dore #1 located in Vermillion Parish, was a 12,500 ft. exploratory test in the Live Oak field and reached total depth subsequent to September 30, 2001. The test, in which we had a 50% interest, proved unsuccessful and the well was plugged and abandoned in October 2001. Our total cost including acreage, promote and dry hole cost was approximately $734,000. In the last half of 2001, we drilled our third exploratory well in Lafourche Parish which was an unsuccessful test.
We acquired leasehold positions in West Broussard, Lafayette Parish and Lake Boeuf, Lafourche Parish.
The Lapeyrouse 3-D Project The Lapeyrouse 3-D Project is located in Terrebone Parrish, Louisiana and covers 1,969 gross acres and 295 net acres. Our working interest is 16.84% and Xplor Energy, Inc. is the operator of the drilling activities. This project, which is located in the prolific Gulf Coast Transition Zone of South Louisiana, targets deeper untested formations, which we consider high potential, as well as shallow development potential. The first well, the T.Cenac #1 as previously discussed, commenced drilling in 2000 and was successfully completed in the first quarter of 2001. Two more wells are planned for the last half of 2002.
The Lafourche Parish Project The Raceland prospect is located in Lafourche Parish, Louisiana, in which we own a working interest of approximately 7.5% was drilled in the last half of 2001. The high potential prospect consisted of two separate untested northwest dipping fault closures and a large fault sealed ridge of significant untested structural closure, downthrown on a large growth fault in the Lower Miocene Robulus sands section. This structure, on 1,000 acres, was identified using all well control, 2-D and 3-D proprietary seismic.
The test well, W. Ponson #1, commenced drilling in July 2001. The 16,800 ft. exploratory test for the Rob sands reached total depth and logged in early October 2001. After a lengthy evaluation period, elections were made by the working interest owners to abandon the well as non-commercial. Our total cost, including acreage, was approxi-mately $562,000.
West Brousard Project, Lafayette Parish We have also acquired evaluated and unevaluated acreage in the West Broussard field. Approximately 1,100 leasehold acres were acquired in 2001 at a cost of approximately $2.2 million. We have formed two offsetting 485-acre units, to the east of existing production. As of December 31, 2001, we own approximately 85% of the westernmost unit, which increased our total proved reserves by approximately 8.1BcfE for 2001. The primary objective of this well is the Bolmex 3 sand. Before drilling in mid to late 2002, we will reduce our current working interest in this prospect to recover a portion or all of our cost and fund a portion of our share of the drilling costs.
Lake Boeuf, Lafayette Parish We have acquired 660 acres on a structural closure identified by 3-D seismic. The prospect is within the overall producing outline of the Lake Beouf field complex. A 15,800 ft. directional well will test six Rob L sands between 12,100 ft. and 13,200 ft. The well is expected to be drilled in the second half of 2002. We have a total cost of approximately $230,000.
OKLAHOMA 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 And Dispositions of Oil And Gas Operations. Presently the net daily average production for these properties is approximately 5,377 McfE of natural gas.
In June 2000, prior to acquisition by us, Red River Energy acquired interests in 124 properties and prospects in 26 fields located in Kansas, Oklahoma 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.
WEHLU Project The largest holding obtained through the Red River Energy acquisition was the West Edmond Hunton Lime Unit (WEHLU), covering 30,000 acres (about 47 square miles) primarily in Oklahoma County, Oklahoma. The field has 55 oil and natural gas wells with stable production holding the entire unit. Beta holds a 98%WI and is operator. At December 31, 2001, WEHLU had proven reserves of approximately 12 BcfE or approximately 43% of our total proven reserves. WEHLU currently produces approximately 3,295 McfE per day or 33% 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 WEHLU with new re-completion and stimulation methods.
To date, two wells have been drilled and a third is currently drilling in the pilot program. The first well drilled tested the lower portion of the Hunton and fluid recoveries were less than anticipated. A plug was set over the lower interval and the upper Hunton has been tested and is currently producing approximately 380 Mcf of natural gas, 5 barrels of oil and 65 barrels of water per day. The second well drilled was not capable of commercial production and has been plugged and abandoned. The third well is currently drilling and should reach total depth by late March 2002.
While the first two wells of the pilot program did not produce the results expected, they did not condemn the project either. It appears the dewatering of the lower Hunton in this portion of the field may not work, so the scope of the project has changed. The dewatering project may be proved up in another portion of the field in the future.
Our joint development partner is anticipating finding primarily gas with oil and water in future wells in the area it is drilling. They have two additional drilling locations identified at this time. Under the terms of the agreement, a minimum of four wells and a maximum of eight wells are to be drilled for the pilot program in the field. The West Edmond Hunton Lime Unit is a very large field and we are still optimistic that additional oil and gas will be recovered through development drilling.
Charlie Project The Charlie Prospect, coal bed methane properties also acquired in the Red River Energy acquisition, has a current daily average production rate of 748 Mcf, a 50% percent increase for 2001. This property was given no value at the time of the acquisition because the low production was used as collateral for a non-recourse note. Since the acquisition, the note was extinguished and production was stimulated in the existing wells. In 2001, three wells were stimulated or reworked and an additional eight wells have been identified for new fracturing stimulation in the future. At December 31, 2001, this project had approximately 434 MMcf of proved reserves. We have a 100% working interest in the project.
McIntosh County Project We hold approximately 12,984 acres (9,497 net acres) of oil and gas leases and have interests in 43 wells (27 net) and operate 34 of those wells in the Hitchita Field. In 2001, we participated in the drilling of seven wells (six discoveries and one dry hole) targeting the Atoka, Booch or Gilcrease sands. With working interests in these wells ranging from 12.5% to 18.75%, a total of approximately $400,000 was expended in 2001. The current production associated from these wells is approximately 890 gross Mcf (120 net Mcf) of natural gas per day.
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 2001, our gas gathering system in this area had gathering revenues of approximately $868,000.
WYOMING The Madden Field Project In 2001, we purchased a 75% working interest in federal leases totaling 2,930 gross acres, (2,198 net acres) within the Madden Field located in Fremont County, Wyoming in the Wind River Basin. We acquired the initial working interest in 1,627 gross acres from Joe C. Richardson, Jr., a director of the Company, for $154,800. (For further information on this transaction, please see Item 13. Certain Relationships and Related Transactions.) This acreage offsets three wells in the Lower Fort Union and Lance formations that have net pay thickness of 1,090' to the south, 660' to the east, and 978' to the west. In addition, we have options on 5,700 acres in the North Madden Area to the north and 5,200 acres in the Birdseye Creek Area to the northwest.
With the decline in natural gas prices in the latter half of 2001, our revised strategy for the Wind River Basin Project in Wyoming, which was originally allocated $4.5 million for the exploration and development thereof, is to farm out the prospect, and continue to evaluate the option acreage. In 2001, natural gas market conditions unfavorably impacted the Rocky Mountain area with natural gas prices received in this area approximately $1.00 per Mmbtu below the NYMEX - Henry Hub spot price. Currently, this pricing relationship has improved and should enhance our current strategy. Based on the remaining term of certain leases, we recognized $127,229 in impairment on this prospect and transferred that amount to the full cost pool at December 31, 2001.
INTERNATIONAL Australia We are currently active in one prospect area located in West Queensland, Australia on the Ethabuka structure. The projected drilling of a well would be an offset to a well drilled in the 1970's but was abandoned due to drilling difficulties. Tentatively, this well is scheduled to drill in 2002 pending the placement of open working interests in the prospect. Tipperary Oil & Gas Pty, LTD would be the operator of the well. It is anticipated we would participate with an approximate 16% interest, which includes a 6% carried working interest.
Summary of Oil and Gas Operations
DRILLING ACTIVITY For the period indicated, the following table sets forth the results of our drilling activities in the fiscal years ended December 31, 2001, 2000 and 1999:
Subsequent to December 31, 2001, we have drilled 2 gross exploratory wells and 0.6 net wells that are either completing or waiting completion.
PRICE AND PRODUCTION DATA 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 production for the periods indicated were as follows:
Year Ended December 31, ------------------------------------------------ 2001 2000 1999 ------------- ------------- --------------
Oil production (Bbl) 114,271 32,614 1,822 Gas production (Mcf) 2,512,484 1,726,416 475,065 Average sales price: Oil (per Bbl) $ 24.72 $ 30.57 $ 23.03 Gas (per Mcf) $ 3.97 $ 4.08 $ 2.44 Average production cost per McfE $ 1.08 $ .71 $ 0.17
Reflects the impact of gas hedge which reduced our 2001 total average gas price per Mcf by $0.25.
The above well information excludes five wells in which we have only a royalty interest.
The components of production costs may vary substantially among wells depending on the methods of recovery and other factors, but generally include production and ad valorem taxes, repairs and maintenance, labor and utilities.
Capitalized costs at December 31, 2001, 2000 and 1999 relating to our oil and gas activities are summarized as follows:
Unevaluated oil and gas properties - United States
As our properties are evaluated through exploration, they will be included in the amortization base. Costs of unevaluated properties in the United States at December 31, 2001, 2000 and 1999 represent property acquisition and exploration costs in connection with our Louisiana, Texas, Oklahoma and Wyoming prospects. The prospects and their related costs in unevaluated properties have been assessed individually. Costs associated with unevaluated leasehold, including brokerage, are assessed annually based on the remaining term of the primary leasehold. At December 31, 2001, unevaluated property, was impaired by $1,272,836, which amount was transferred to U.S. evaluated costs, or the full cost pool. The current status of the unevaluated prospects is that seismic has been acquired, processed and is interpreted on a current and prospective basis on the subject lands within the prospects. Drilling commenced on certain prospects in the first quarter of 1999. As the prospects are evaluated through drilling, the property acquisition and exploration costs associated with the wells drilled are transferred to evaluated properties and become subject to amortization.
Unevaluated oil and gas properties - Foreign
At December 31, 2001, unevaluated costs outside the United States, represent costs in connection with the evaluation and cost of the Australian concession.
Evaluated Properties - United States
The property acquisition and exploration costs associated with the wells drilled (completed or plugged and abandoned) are transferred to evaluated properties. In 2001, we participated in the drilling of 49 wells within the United States. At December 31, 2001 and at September 30, 2001, total cost in evaluated properties exceeded their net realizable value. A total full cost impairment of $13,805,035 was recognized in 2001. Depletion expense of $4,858,364 was recorded in 2001. For further discussion, please refer to Item 8. Financial Statements and Supplementary Data, Note 2. Acquisitions And Dispositions of Oil And Gas Operations.
At December 31, 2000, evaluated property cost was $44,398,497 which included $28,371,531 associated with the Red River Energy acquisition. In 2000, we participated in the drilling of 21 wells within the United States. No impairment was recorded for 2000. Depletion expense of $2,604,628 was recorded in 2000.
At December 31, 1999, it was determined that the total costs for evaluated properties of $8,128,928 exceeded their net realizable value by $1,167,910. Accordingly, an impairment charge for this amount was recorded for the year ended December 31, 1999. Production commenced during the period and depletion expense of $901,573 was recorded.
Evaluated Properties - Foreign
During 1998, Beta, through its wholly owned subsidiary, BETAustralia, LLC secured an option to participate for a 5% working interest in two petroleum licenses covering 2,798,000 acres (approximately 4,372 square miles). Per the terms of the option agreement, Beta exercised its option to earn a 5% working interest by participating in the drilling of two offshore test wells in the license areas. The wells were completed as dry holes. The property acquisition and exploration costs associated therewith totaling $1,624,218 were transferred to evaluated properties and charged to impairment expense during the year ended December 31, 1998. The exploration licenses expired in December 1998. Property acquisition and exploration costs associated with foreign prospects totaling $57,052 were transferred to evaluated properties and charged to impairment expense during the year ended December 31, 1999. Beta has generated no revenues from its foreign properties to date.
For further information on oil and gas operations, please see Item 8. Financial Statements and Supplementary Data, Note 2. Acquisitions And Dispositions of Oil And Gas Operations.
Principal Products Our principal products are natural gas and crude oil.
Patents, Trademarks, Licenses, Franchises and Concessions Held Permits, licenses and oil and gas leases are important to our operations, as they allow the search for the extraction of any oil, gas and minerals discovered on the areas covered. See further, Item 2
Item 2. Properties of Beta General: 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 our leases. Our revolving credit facility is collateralized by the reserves associated with our proved producing properties and our producing oil and gas properties.
PRODUCTIVE WELLS AND ACREAGE We have presented the following table to provide you with a summary of the producing oil and gas wells and the developed and undeveloped acreage in which we owned an interest at December 31, 2001. We have not included in the table, acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests.
(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.
At December 31, 2001, approximately 19,022.1 gross acres and 5,915.6 net acres will expire in 2002.
In addition to the interests we own in developed and undeveloped acreage, at December 31, 2001 we have options to acquire interest in: 1.) an additional 10,032 gross (3,344 net) acres in Jackson County, Texas which expire April 16, 2002; and 2.) an additional 13,800 gross (10,350 net) acres in Fremont County, Wyoming, which expire May 3, 2002. We do not expect to renew these options.
OIL AND NATURAL GAS RESERVES At December 31, 2001, we had proved reserves of 836.8 Mbbls of oil and 24.7 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, 2001, the present value of our future net revenues (revenues less production and development cost) before income taxes attributable to these reserves.
The above figures do not reflect the future net revenues before income taxes and the present value of future net revenues, discounted at 10%, for our McIntosh gathering system, which were $858,199 and $670,579, respectively.
For purposes of estimating 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 proved oil and gas reserves. The average year-end price for oil and natural gas was $18.17/Bbl and $2.65/Mcf at December 31, 2001. Future development and production costs were computed by applying year-end costs to be incurred in producing and further developing the proved reserves. The estimated future net revenue was computed by application of a 10% discount factor. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such arbitrary assumptions have not proven to be the case in the past. 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 2001.
Item 3.
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 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 seeking damages for the unpaid charges of $282,096.
Subsequent to December 31, 2001, we have settled the above claim and counterclaim with ONEOK through independent mediation. It was mutually agreed to release all claims and Beta will pay ONEOK $43,000 in addition to the $282,096 of funds currently held by ONEOK. Each party will be responsible for their legal fees and costs associated with this matter of which our total legal fees were approximately $85,600. In regards to this settlement, 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 our counterclaim.
Item 4.
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, 2001.
PART II
Item 5.
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 sale prices of our common stock as reported on the Nasdaq Small Cap Market for the 1st quarter of 2000 and the Nasdaq National Market for the remaining three quarters of 2000. and for the all quarters in 2001. 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.
2001 High Low ---- ---- ---- 1st Quarter....... $ 9.13 $ 6.75 2nd Quarter...... 8.83 6.56 3rd Quarter...... 8.06 4.95 4th Quarter....... 6.45 3.80
1st Quarter....... $ 10.56 $ 6.53 2nd Quarter...... 10.88 7.75 3rd Quarter...... 12.00 7.75 4th Quarter....... 9.38 6.81
Approximately 232 shareholders of record and approximately 2,220 beneficial owners as of March 15, 2002 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.
Item 6.
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.
Item 7.
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, 2001 and 2000, and the results of operations for the years ended December 31, 2001, 2000 and 1999.
General
During 2001, our economy slipped into a recession due to weakened demand for products creating surplus inventories in a majority of business sectors. The energy sector, which was not an exception, experienced a significant decline in demand and consequently inventory levels for both natural gas and crude oil materially increased over the previous year's inventory levels. With the significant build up of inventory by mid-2001, commodity prices for natural gas and crude oil decreased approximately 75% and 30%, respectively, from the beginning of the year. Demand for drilling has significantly decreased during the last half of 2001 with a decrease in exploration activity.
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 commitment. 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.
Our working capital was a deficit of ($103,550) at December 31, 2001 compared to surpluses of $3,533,237 at December 31, 2000 and $2,034,268 at December 31, 1999. The significant decrease to our working capital was due to higher capital expenditures associated with our intensified drilling and lease acquisition activity principally occurring in the last half of 2001. Our capital program 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. Approximately $15.1 million was expended during the year on our exploration and development program, including the acquisition of additional working interests in production and leasehold acreage, both evaluated and unevaluated. Approximately $4.4 million was expended in the fourth quarter on additional lease acquisition in our West Broussard area and the drilling of: 1.) the Signal Hill #1 - Big Twelve Wilcox test well, 2.) the Ponson #1 - Raceland "S" sand test well, 3.) the Elk Hills #1 - - Texana Wilcox test well, 4.) the Rubel #1 - Sara White test well, and 5.) 11 test or development wells in the Brookshire Dome area. For the year our results from our exploration program have been disappointing in regards to the discovery of any significant field or extensions.
However, we have increased proved reserves for 2001 by 5.4 BcfE or 22%, which was primarily the result of the completion of leasing and the unitization of our West Broussard prospect which added approximately 8.1 BcfE of proved undeveloped reserves. Our proved developed reserves declined by 3.1 BcfE or 13%. Our proved developed discoveries were offset by the current year's production and downward revision of reserves. This was due to lower commodity prices, higher operating expenses associated with our WEHLU production and downward volume revision due to lack of production history, related to the Brookshire Dome area.
Our liquidity has been significantly reduced during the year by our aggressive drilling and exploration program and a significant decrease in natural gas and crude oil prices. Our principal source of short-term liquidity is from operating cash flow. Should natural gas and crude oil prices decrease further, our current operating cash flow would decrease and further reduce our liquidity. Our short-term liquidity and working capital should increase in the first quarter of 2002 due to a significant decrease in capital expenditures as our late 2001 drilling projects near completion and lower overall drilling activity. An additional source of short-term liquidity will be funds received from the reduction of our interests in certain unevaluated or proved undeveloped projects. To date, subsequent to December 31, 2001, we have received approximately $585,400 from the sale of interests in our West Broussard, Lake Boeuf and North Mexican Sweetheart prospects. We intend to further reduce our working interest in these and other unevaluated projects to enhance our risk profile and raise additional working capital for our 2002 capital program and debt reduction.
In 2001,with the decline of commodity prices and a reduction in our proved developed reserves, 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 further 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 funds generated from the sale of unevaluated or proved undeveloped prospects to make this pay down. The next re-determination will take place in April 2002.
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.
(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 Supplement Data, Note 4, Long Term Debt. (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.
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:
o Use of estimates o Oil and gas properties o Derivative instruments and hedging activity o Concentration of credit risk
Certain accounting principals 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 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 based on the remaining term of the primary leasehold. At December 31, 2001, unevaluated leasehold costs were impaired for $1,272,836 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.
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 purchaser due to the location of the production and lack of alternate sources of purchasers. In this particular instance, Duke Energy is the purchaser.
Effects of Transactions With Related and Certain Other Parties In March 2001, we entered into an Exploration and Development Area of Mutual Interest Agreement in Fremont County, Wyoming with Mr. Joe C. Richardson, Jr., one of our outside directors. We purchased from Mr. Richardson certain geology and approximately 1,627 leased acres in a prospect located therein for $154,800. We acquired a 75% working interest in the prospect while Mr. Richardson retained a 25% working interest and a 5% royalty interest. All future exploration and development costs are to be shared accordingly. At the time of the transaction, we had projected drilling to commence on this prospect in the last half of 2001. However, with the decline in natural gas prices in the last half of 2001, our revised strategy for the Wind River Basin Prospect is to farm out the initial drill site, and continue to evaluate the option acreage. In 2001, natural gas market conditions unfavorably impacted the Rocky Mountain area with natural gas prices received in this area approximately $1.00 per Mmbtu below the NYMEX - Henry Hub spot price. At December 31, 2001, based on the remaining term of certain leases, we recognized an impairment of $127,229 on this prospect and transferred that amount to the full cost pool.
In the fourth quarter of 2001, we sold approximately 6.37% in our Matterhorn, Jackson County Texas prospect and 7.96% in our Sara White, Galveston County, Texas prospect to Waveland Drilling Partners 2001, L.P. (Waveland Partners). The interests were sold to Waveland Partners on standard industry terms for both the acreage and participation in the subsequent drilling of the prospects. We received approximately $355,989 for the acreage and received a promote on the dry hole cost related to the drilling of these wells. Subsequent to 2001, Waveland Drilling Partners 2002A, L.P. has acquired 8.5% in our West Broussard, Lafayette Parish, Louisiana prospect and 10% in our Lake Boeuf, Lafourche Parish, Louisiana prospect on similar terms. We may sell interests in other prospects should Waveland Partners agree to our terms.
Plan of Operation for 2002
For the year 2002, we expect to fund our capital requirements from net cash flow from operations (after general and administrative expense) and proceeds received from the reduction or sale of our working interest in certain undrilled projects.
We project our 2002 capital expenditure to be approximately $7 million. The areas and amounts of concentration for the capital program will be:
o Jackson County, Texas - $1.2 million o Red River and Lamar Counties, Texas - $.8 o Galveston County, Texas - $1.7 million o Louisiana - $1.7 million o Waller County, Texas - $1.0 million o Other, including Australia - $.6 million
The allocation of the 2002 capital forecast may change materially pending the results of the Elk Hills #1, Jackson County, Texas Wilcox test well.
We are projecting our cash flows from operations to be approximately $4.8 million based on an average natural gas price of $2.37 per Mcf and $18.88 per barrel and average net daily production of 10.0 MMcfE. Estimated proceeds from sale and reduction of our working interests in certain evaluated and unevaluated prospects are approximately $3.4 million. 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. Additionally, lower natural gas and crude oil prices could adversely impact our ability to receive any proceeds from the sale of our prospects. If this happens, it may be necessary for us to raise additional funds.
We have approximately 375,725 callable common stock purchase warrants outstanding exercisable at a price of $7.50 per share. We are able to call these warrants at any time after our common stock has traded on Nasdaq at a market price equal to or exceeding $10.00 per share for 10 consecutive days which was achieved in July 2000. It is our intent to call all of these warrants at such time, if and when, the cash is needed to fund capital requirements. We will receive proceeds equal to the exercise price times the number of shares which are issued from the exercise of warrants net of commission to the broker of record, if any. We could realize net proceeds of approximately $2,814,500 from the exercise of all of these warrants. There is no assurance that any warrants will be exercised or that we will ever realize any proceeds from the $7.50 warrant calls. However, due to current market conditions and the current price of our stock, it is not probable that we will call these warrants in the first half of 2002.
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 did not have sufficient proved producing reserve collateral to support a conventional bank loan.
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 presently being completed and equipped for production. For 2002, we currently estimate that the wells will generate approximately $7.5 million of net cash flow after deducting lease operating expenses of approximately $3.0 million.
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 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.
Our long-term goal is to continue the pattern of growing the Company by accumulating oil and gas reserves through acquisition and 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, 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 ($4,879,718 net of income tax) and at December 31, 2001 of $7,034,925 ($5,070,590 net of income tax). 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.
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. This operating cost per equivalent Mcf is significantly higher than the 2001 average for the remaining properties of $.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 Energy acquisition and outside services, which provide 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 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.
Year ended December 31, 2000 and Compared to Year ended December 31, 1999
We have reported net income of $1,425,565 for the year ended December 31, 2000 compared to a net loss of ($5,348,403) for the same period ended 1999. Our results of operations have been significantly impacted by our ability to increase production through our exploration activities and acquiring oil and gas properties. Fluctuations in natural gas and crude oil prices have also significantly impacted these results.
The following table summarizes key items of comparison and their related increase (decrease) for the twelve months ended December 31 for the periods indicated.
For the twelve months ended December 31, 2000 oil and gas sales increased $6,837,700 or 570% from the same period ended 1999. A 263% increase in natural gas production combined with a 67% increase in average natural gas prices accounted for approximately $5,700,000 of the increase. A 1711% increase in crude oil production for 2000 and a 33% increase in average 2000 crude oil prices accounted for the remaining $1,100,000 increase in oil and gas sales. The increase in natural gas and oil production for 2000 was due to additional wells drilled and completed during the year and incremental natural gas and crude oil production acquired in the Red River Energy acquisition. Approximately 67% of the increase in our natural gas production was due to new wells drilled and completed during the twelve months ended December 31, 2000. Acquired crude oil production accounted for approximately 88% of the increase in oil production for the year. Higher natural gas prices for 2000 resulted in approximately $2,800,000 in additional oil and gas revenues. 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. However, fixed pricing from hedges only cover 22% of our production on an equivalent Mcf basis. Based on our 2000 natural gas production, a change in the average natural gas price we realized of $1.00 per Mcf would have resulted in an approximate $1.5 million reduction in net income before income taxes.
Operating expenses, including production and ad valorem taxes, increased approximately $1,287,250, or 1580%, to $1,368,788 for the year ended 2000. The increased expenses were due to approximately $1,000,000 of additional operating expenses associated with the Red River Energy acquisition properties, which included a gathering system, and the increase in number of wells put on production for the year. The average operating expense for the Red River Energy acquisition oil and gas wells was $1.51 per equivalent Mcf for the period September 1, 2000 through December 31, 2000. This operating cost per equivalent Mcf is significantly higher than the average for the remaining properties of $.33 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 which was acquired in the Red River Energy acquisition. There was no comparable expense in 1999.
G&A expenses for the twelve months ended December 31, 2000 increased in absolute dollars by approximately $722,800 but decreased $1.80 on a per equivalent Mcf basis from the same period in 1999. The following shows the major items accounting for the 2000 increase:
o Relocation and severance expense associated with our corporate office move from Newport Beach, CA to Tulsa, OK of $289,000 which included a non-cash charge of $128,000 associated with the vesting rights on stock warrants of a former officer/employee
o Incremental increase in costs associated with additional employees hired from the Red River Energy acquisition, which was approximately $261,000 for the four-month period September 2000 through December 2000
o Fees of approximately $124,000 associated with our entry on NASDAQ's National Market system
o Overall increase in corporate expenses of approximately $120,000 due to increased level of activity from our growth.
Depletion and depreciation expense increased $1,779,206, or 195%, to $2,693,439 for 2000 from $914,233 in 1999 due to increase production volume in 2000. Our average depletion and depreciation rate per equivalent Mcf for 2000 decreased 26% to $1.40 from $1.88 in 1999 primarily as a result of the reserves acquired in the Red River Energy acquisition and those reserves discovered from our exploration effort during the year.
There was no impairment expense for the twelve-month period ended December 31, 2000 due to the determination of the total evaluated costs in both the U.S. and foreign cost pools exceeding their net realizable value. In 1999, it was determined that the total costs in the U.S. evaluated properties cost pool exceeded their present value and accordingly an impairment write-down of $1,167,910 was recorded. The impairment was due mainly to downward revisions of reserve estimates associated with two wells drilled in 1998. The downward revisions were due to disappointing production results from the wells in the fourth quarter of 1999 when producing zones in the wells commenced significant production of salt water in place of gas and oil. Additionally, a $57,052 impairment charge was recorded for our evaluated cost associated with our Australian properties.
Interest expense decreased for the year ended December 31, 2000 compared to the same period for 1999 primarily due to the retirement of our bridge notes, which were retired in July 1999. Interest expense related to the bridge notes for 1999 consisted of the following:
The decrease was partially offset by the interest expense we incurred in 2000 as a result of debt acquired in the Red River Energy acquisition.
Income Taxes As of December 31, 2001, we had available, to reduce future taxable income, a Federal net operating loss carryforward of approximately $12,657,100, which expires in the years 2012 through 2021. 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, 2001 we had no deferred taxes.
Impact of Recently Issued Standards In June 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141 "Business Combinations" ("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for under the purchase method. For all business combinations for which the date of acquisition is after June 30, 2001, SFAS 141 also establishes specific criteria for the recognition of intangible assets separately from goodwill and requires unallocated negative goodwill to be written off immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 changes the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for intangible assets with finite lives will no longer be limited to forty years. We do not believe that the adoption of these statements will have a material effect on our financial position, results of operations, or cash flows.
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 this time, we cannot reasonably estimate the effect of the adoption of this statement on our financial position, results of operations, or cash flows.
In October 2001, the FASB also approved SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 replaces SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, for the disposal of segments of a business. Statement 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. Statement 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of Statement 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally, are to be applied prospectively. At this time, the Company cannot estimate the effect of this statement on its financial position, results of operations, or cash flows.
Item 7A.
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 2001 production rate, we have approximately 29% of our current natural gas production hedged for January and February 2002 increasing to approximately 53% for the remainder of 2002 until January 2003. We have approximately 41% of crude oil hedged through March 2003. We use costless collars to hedge our production. For more information please refer to Item 8.
Item 8. Financial Statements and Supplementary Data.
Our financial statements and supplementary financial data, which begin on page, are included elsewhere in this report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.
PART III
Item 10.
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 2002 annual meeting under the headings "Proposal One -- Election of Directors," "Executive Officers" and "Section 16(a) Beneficial Ownership Reporting Compliance."
Item 11.
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 2002 annual meeting under the heading "Executive Compensation."
Item 12.
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 2002 annual meeting under the heading "Principal Stockholders and Security Ownership of Management."
Item 13.
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 2002 annual meeting under the heading "Certain Transactions."
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a) The following documents are filed as part of this report:
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. Consent of Hein + Associates, LLP. dated March 28, 2002 Consent of Ryder Scott and Associates dated March 28, 2002
For a list of Financial Statements and Schedules, see "Index to the Financial Statements and Schedules" on page
(b) No reports on Form 8-K were filed during the fourth quarter ended December 31, 2001:
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)
10.14BWC 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).
10.19Redfish 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)
10.24Northeast 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)
10.25Sarah 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).
10.29Mushroom 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).
10.30Starboard 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).
10.31First 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).
10.32First 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).
10.33Second 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).
10.34Third 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).
10.35Form 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.
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 28, 2002
23.3 Consent of Ryder Scott and Associates dated March 28, 2002
99 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).
Beta Oil & Gas, Inc. and Subsidiaries
Consolidated Financial Statements For the Years Ended December 31, 2001, 2000 and 1999
Page
Independent Auditor's Report..........................................F-2
Consolidated Balance Sheets - December 31, 2001 and 2000..............F-3
Consolidated Statements of Operations - For the Years Ended December 31, 2001, 2000 and 1999...............................F-4
Consolidated Statement of Stockholders' Equity - For the Years Ended December 31, 2001, 2000 and 1999.................................F-5
Consolidated Statements of Cash Flows - For the Years Ended December 31, 2001, 2000 and 1999...............................F-7
Notes to Consolidated Financial Statements............................F-9
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, 2001 and 2000, and the related consolidated statements of operations, stockholders' equity, and cash flows for the three years in the period ended December 31, 2001. 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, 2001 and 2000 and the results of their operations and their cash flows for the three years in the period ended December 31, 2001 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 15, 2002
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS'EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
(Continued)
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999 (CONTINUED)
See accompanying notes to consolidated financial statements.
BETA OIL & GAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Continued)
BETA OIL & GAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Continued)
See accompanying notes to consoidated financial statements.
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 Companys 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.
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.
2001 2000 ----------------- -----------------
IP Petroleum (Pure) 8% 31% Duke Energy 29% 19% Cokinos Energy 5% 13% Allegro Investments 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. We had no direct sales contracts or derivatives with the Enron Corporation ("Enron"). Genesis Crude Oil, LP, a purchaser of our crude oil for the Brookshire Dome area, did re-sell one month (November 2001) of crude oil production to a subsidiary of Enron. However, at this time we have received payment from Genesis for that month and are not aware of any adverse effect on Genesis. We cannot guarantee that through the re-sale process there may be other situations similar to the one previously discussed but we are not aware of any additional dealings with Enron at this date.
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, account receivable and accounts payable approximates their carry 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.
New Accounting Pronouncements - In June 2001, the Financial Accounting Standards Board ("FASB") issued Statements of Financial Accounting Standards No. 141 "Business Combinations" ("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142"). SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for under the purchase method. For all business combinations for which the date of acquisition is after June 30, 2001, SFAS 141 also establishes specific criteria for the recognition of intangible assets separately from goodwill and requires unallocated negative goodwill to be written off immediately as an extraordinary gain, rather than deferred and amortized. SFAS 142 changes the accounting for goodwill and other intangible assets after an acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and intangible assets with indefinite lives will no longer be amortized; 2) goodwill and intangible assets with indefinite lives must be tested for impairment at least annually; and 3) the amortization period for intangible assets with finite lives will no longer be limited to forty years. The Company does not believe that the adoption of these statements will have a material effect on its financial position, results of operations, or cash flows.
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 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 this time, the Company cannot reasonably estimate the effect of the adoption of this statement on its financial position, results of operations, or cash flows.
In October 2001, the FASB also approved SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets. SFAS 144 replaces SFAS 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. The new accounting model for long-lived assets to be disposed of by sale applies to all long-lived assets, including discontinued operations, and replaces the provisions of APB Opinion No. 30, Reporting Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, for the disposal of segments of a business. Statement 144 requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. Therefore, discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. Statement 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of Statement 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001 and, generally, are to be applied prospectively. At this time, the Company cannot estimate the effect of this statement on its financial position, results of operations, or cash flows.
2. ACQUISITIONS AND DISPOSITIONS OF OIL AND GAS OPERATIONS:
Acquisitions - 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 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 coal bed 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 coal bed properties as a purchase price allocation as the coal bed 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.
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:
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.
(2) Net of $710,000 related to sale of evaluated oil and gas properties. (3) Net of $355,989 related to sale of unevaluated oil and gas properties. (4) Includes $24,845,227 related to the properties acquired in the Merger and $3,526,304 related basis from deferred taxes. (5) At December 31, 1999, the total costs in U.S. and foreign evaluated properties exceeded their net realizable values and accordingly an impairment write down of $1,224,962 was recorded.
Evaluated oil and gas properties
United States - 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. Amortization expense was $4,858,364 or $1.51 per Mcf for equivalent units of gas produced. Crude oil is converted to equivalent units of gas on the basis of one barrel of oil to six equivalent Mcfs of gas.
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 transferred to evaluated properties. Amortization expense was $2,604,328 or $1.35 per equivalent Mcf units of oil and gas produced. Oil is converted to equivalent units of natural gas on the basis of one barrel of oil to six equivalent Mcfs of natural gas.
During the year ended December 31, 1999, Beta participated in the drilling of 19 wells within the United States. The property acquisition and exploration costs associated with the wells were transferred to evaluated properties. It was determined that the total costs in the U.S. evaluated properties cost pool exceeded their net realizable value. Accordingly, an impairment write-down of $1,167,910 was recorded for the year ended December 31, 1999. Production commenced during the year and depletion expense of approximately $901,573 was recorded or $1.86 per equivalent Mcf units of oil and gas produced. Oil is converted to equivalent units of natural gas on the basis of one barrel of oil to six equivalent Mcfs of natural gas.
Due to the volatility of commodity prices and/or exploration 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 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 year ended December 31, 2001 and 2000.
During 1998, Beta, through its wholly owned subsidiary, BETAustralia, LLC secured an option to participate for a 5% working interest in two petroleum licenses covering 2,798,000 acres (approximately 4,372 square miles). Per the terms of the option agreement, Beta exercised its option to earn a 5% working interest by participating in the drilling of two offshore test wells in the license areas. The wells were completed as dry holes. The property acquisition and exploration costs associated therewith totaling $1,624,218 were transferred to evaluated properties and charged to impairment expense during the year ended December 31, 1998. The exploration licenses expired in December 1998. Additional costs of $57,052 were transferred to and charged to impairment expense during 1999.
The results of operations for producing activities are provided below:
Unevaluated oil and gas properties
At December 31, 2001, 2000 and 1999, unevaluated properties consist of the following:
December 31, 2001 2000 1999 --------------- -------------- ----------------
Unproved $ 6,946,580 $ 8,547,825 $ 7,056,414 Exploration 6,054,863 4,902,522 5,035,213 --------------- -------------- ---------------- $13,001,443 $ 13,450,347 $ 12,091,627 =============== ============== ================
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, 2001, 2000 and 1999 represent property acquisition and exploration costs in connection with the Company's Louisiana and Texas 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 based on the remaining term of the primary leasehold. At December 31, 2001, unevaluated leasehold costs were impaired for $1,272,836 and transferred to U.S. evaluated costs, or the full cost pool. For the remaining costs, which include seismic and geological and geophysical, the Company estimates reserve potential for the unevaluated properties using comparable producing areas or wells and risk that estimate by 50-75%. 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 are unknown to the Company at the time of its assessment, a materially different result could occur.
The current status of these prospects is that seismic has been acquired, processed and reprocessed and is being interpreted on an ongoing basis on the subject lands 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 base.
Management anticipates that the planned activities for 2002 will enable the evaluation for approximately 50% of the costs as of December 31, 2001 and the remaining 50% of the costs will occur in 2003 and 2004.
Foreign - Costs of unevaluated properties outside the United States represents costs in connection with the acquisition of properties in Australia. Management expects 100% of this cost to be evaluated in 2002. The Company anticipates the drilling of one well on this concession, in which it expects to retain 10% of its current 25% interest, in 2002.
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 year ended December 31, 2001 and 2000, the Company recorded depreciation expense of $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 $67,306, $32,567 and $12,660 for the years ended December 31, 2001, 2000, and 1999, respectively.
At December 31, 2001 and 2000, 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.
4. LONG-TERM DEBT:
Long-term debt consisted of the following:
The $13,634,652 note at December 31, 2001 arises from a credit agreement with a commercial bank that provides for maximum outstanding borrowings aggregating $25 million limited to a collateral borrowing base of $14,400,000, which will be redetermined semi-annually. The Company is required to maintain certain covenants of which the Company was in compliance at December 31, 2001.
Aggregate maturities required on long-term debt at December 31, 2001 are due in future years as follows:
2002 $ 57,407 2003 13,648,727 2004 - 2005 - 2006 - --------------- Total $ 13,706,134 ===============
5. BRIDGE NOTES - NOTES PAYABLE:
During the year ended December 31, 1999 the Company completed the private placement of a $3,000,000 bridge promissory note financing to three institutional investors (the "1999 bridge financing"). In connection with the 1999 bridge financing, the Company granted the investors a security interest in all of its assets. In addition, a total of 459,000 shares of the Company common stock were issued in connection with the 1999 bridge financing. The $3,000,000 in bridge notes was repaid in full with accrued interest on July 7, 1999 from the proceeds of the Company's initial public offering.
The Company received net cash proceeds of $2,835,000 from the bridge notes. The estimated fair market value of 429,000 shares of common stock issued in connection with the bridge note of $2,574,000 was treated as a discount and was amortized over the term of the promissory notes using the interest method. The estimated fair market value of 30,000 additional shares of common stock issued per the terms of the bridge note of $180,000 was immediately expensed as interest during the year ended December 31, 1999. Accordingly, the Company incurred additional interest expense of $2,754,000 because of the common stock issued in connection with the bridge notes. The debt issuance costs of the 1999 bridge financing of $89,100 were amortized as additional interest expense during the year ended December 31, 1999.
6. 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.
Future minimum lease payments for all non-cancelable operating leases are as follows:
YEARS ENDING DECEMBER 31, AMOUNT ------------------------- -------------
2002 $ 179,068 2003 159,967 2004 22,975 2005 5,927 2006 - ------------- TOTAL $ 367,937 =============
Rent expense was $170,338, $125,640 and $33,000 for the years ended December 31, 2001, 2000 and 1999, 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.
Subsequent to December 31, 2001, the Company has settled the above claim and counterclaim with ONEOK through independent mediation. It was mutually agreed to release all claims and Beta will pay ONEOK $43,000 in addition to the $282,096 of funds currently held by ONEOK. Each party will be 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 September 2001, the Company participated with a 62.5% interest in the drilling of the Dore #1, Live Oak Prospect located in Vermillion 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 to conduct a groundwater investigation to determine the extent of groundwater contamination, if any. The estimated costs 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.
7. 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 recorded a gain of $734,031 (net of $489,353 income tax) in the first quarter ended March 31, 2001 and a gain of $219,457 (net of $146,305 income tax) in the second quarter ended June 30, 2001. Based on the derivative contract date, all of the transition adjustments initially recorded in accumulated other comprehensive loss were reclassified to earnings in the second quarter of 2001.
For the twelve months ended December 31, 2001, the Company had a realized loss of $340,048 relative to its hedging activities.
Natural Gas - At December 31, 2001, the Company had the following commodity price hedging contracts outstanding as set forth below with respect to its 2001 and 2002 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.
NYMEX Contract Price per MMBtu --------------------------------- Volume in Collars Period MMBtus Floor Ceiling
Sept 01 - Feb 02 362,000 $3.50 $3.85
At December 31, 2001, the outstanding contracts had a fair market value of $35,631 (net of $23,755 income tax) and accordingly, the Company recorded a derivative asset for such amount. These contracts are costless and no net premium is received in cash or as a favorable rate.
Crude Oil - At December 31, 2001, the Company had the following commodity price hedging contracts outstanding as set forth below with respect to its 2001 and 2002 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.
NYMEX Contract Price per Barrel ------------------------------- Volume in Collars Period Barrels Floor Ceiling
Oct 01- Mar 02 30,000 $25.00 $27.90
At December 31, 2001, the outstanding contracts had a fair market value of $32,877 (net of $21,919 income tax) and accordingly, the Company recorded a derivative asset for such amount. These contracts are costless and no net premium is received in cash or as a favorable rate.
8. 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 will pay quarterly cash dividends commencing in the quarter that the Preferred Shares are issued, at an annual rate of 8% per annum, simple interest. If the Preferred Shares are automatically converted into common stock or called by the Company within one year of the issuance each holder of the Preferred shares will receive a full year's dividend less any dividends previously paid during the year.
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, 2001, the liquidation preference was approximately $5,923,834. Warrants are non-transferable and may be exercised at any time through June 29, 2006.
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 over the next four months. The repurchase program was effective immediately. At December 31, 2001, the Company had reacquired 42,500 shares for a total cost of $198,920 or $4.68 per share.
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. The timing and amount of shares actually purchased will be determined at Beta management's discretion, based on market conditions and other factors
Warrants -
The Company issued 56,000, 225,000 and 51,000 warrants to employees and directors of the Company during the years ended December 31, 2001, 2000 and 1999 with exercise prices, equal or greater than the market price on the date of grant, ranging from $5.00 per share to $10.25 per share. The warrants issued vested immediately and expire between 2004 and 2006.
During the years ended December 31, 2000 and 1999, the Company issued 75,000 and 50,000 warrants with exercise prices of $7.75 and $6.00, 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 and $102,135 using the Black- Scholes valuation model with a volatility ranging from 50.1% to 54.4%, risk free interest rates ranging from 5.72% to 5.77% and an estimated time to expire of three years. The warrants vest immediately and begin to expire in 2006.
During the year ended December 31, 1999, the Company issued 85,000 warrants in connection with consulting and legal services received during the year. The warrants have exercise prices ranging from $6.00 to $6.38, vested immediately, and expire beginning in the year ended December 31, 2004. The warrants were valued at $126,890 using the Black Scholes valuation model with a volatility of 54.4%, risk free interest rate ranging from 5.70% to 5.84%, and a two-year period to expiration.
On June 21, 1999, certain warrant holders agreed to cancel 87,296 warrants to purchase common stock consisting of 20,000 warrants exercisable at $5.00 per share and 67,296 warrants exercisable at $7.00 per share. All of the canceled warrants were non-callable with expiration dates on March 12, 2003. The warrants were cancelled for no consideration pursuant to a request by the National Association of Securities Dealers, the "NASD". The warrant holders were certain NASD member firms and their employees who participated in Beta's 1998 private placement, as well as Beta's legal counsel. The cancellation request was made and complied with because the NASD determined that these warrants could be deemed "underwriters compensation"; and the continued existence of these warrants could result in the compensation for the initial public offering exceeding the NASD guidelines.
The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants as of December 31, 2001:
AVG EXERCISE NO. OF SHARES PRICE/SHARE ----------------- ------------
BALANCE, January 1, 1999 2,497,663 $ 5.24 Granted 319,122 6.48 Forfeited/Cancelled (87,296) 6.54 Exercised (446,142) 4.60 ---------------- ------------ BALANCE, December 31, 1999 2,283,347 5.49
Granted 400,000 9.26 Forfeited/Cancelled (60,149) 7.75 Exercised (665,827) 4.68 ---------------- ------------ BALANCE, December 31, 2000 1,957,371 6.46
Granted 469,915 9.02 Forfeited/Cancelled (50,000) 8.13 Exercised (57,621) 3.14 ---------------- ------------ BALANCE, December 31, 2001 2,319,665 $ 7.05 ================ ============
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, 2001, 832,415 warrants were callable with a weighted average exercise price of $8.44 per share. The remaining 1,487,250 warrants outstanding are non-callable warrants with a weighted average price of $6.27 per share. If not previously exercised, 474,257 warrants will expire in 2002, 769,587 warrants will expire in 2003, 460,906 warrants will expire in 2004, 191,000 warrants will expire in 2005, 408,915 warrants will expire in 2006 and 15,000 warrants will expire in 2007.
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 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.
During the year ended December 31, 2001, the Company granted 93,500 options, under the 1999 Plan to certain employees at an average exercise price of $4.60 per share which was greater than the market price on the date of grant. The options vested immediately and expire in 2011.
In December 2000, the Company granted options to purchase 135,000 shares of common stock to employees under the 1999 plan. The options were granted with an exercise price of $7.70 per share which was greater than the market price on the date of grant. The options vested immediately and expire in 2009.
In September 2000, the Company granted options to purchase 51,000 shares of common stock to employees under the 1999 plan. The options were granted with an exercise price of $9.00 per share which was greater than the market price on the date of grant. The options expire in 2009 and vest over three years.
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.
The following table sets forth activity for all options granted under the 1999 Plan:
AVG EXERCISE NO. OF SHARES PRICE/SHARE ------------- --------------- BALANCE, December 31, 1999 - - Granted 283,500 $ 7.35 Forfeited/Cancelled (2,500) 6.00 Exercised (15,000) 6.00 ------------- --------------- BALANCE, December 31, 2000 266,000 $ 7.44 Granted 93,500 4.60 Forfeited/Cancelled - - Exercised - - ------------- --------------- BALANCE, December 31, 2001 359,500 $ 6.70 ============== ===============
At December 31, 2001, 340,500 options to purchase shares were exercisable at prices ranging from $4.00 to $9.00 per share. The remaining 19,000 options outstanding will vest ratably through 2002 with an exercise price of $9.00 per share.
If not previously exercised, the outstanding plan options will expire as follows:
NO. OF AVG EXERCISE PERIOD ENDED DECEMBER 31, SHARES PRICE/ SHARE --------------------------- ------------ --------------
2009 80,000 $ 6.00 2010 186,000 8.06 2011 93,500 4.60 ----------- -------------- 359,500 $ 6.70 =========== ==============
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 2001, 2000 and 1999 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 from 5.07% to 6.05%, expected life of two to three years; dividend yield of 0%; and expected volatility ranging from 0% to 54.42%. The weighted-average fair value of the options on the grant date for the years ended December 31, 2001, 2000 and 1999 was $1.23, $3.18 and $1.68 per share, respectively.
9. INCOME TAXES:
Income tax benefit (expense) for the indicated periods is comprised of the following:
For the Years Ended December 31, 2001 2000 1999 ------------- ------------- ------------- Current Federal $ (17,000) $ (51,000) $ - State (4,872) (243,300) - ------------- ------------- -------------
$ (21,872) $ (294,300) $ - ============= ============= ============= Deferred Federal $ 2,367,562 - - State 1,158,742 - - ------------- ------------- ------------- $ 3,526,304 $ - $ - ============= ============= =============
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:
The components of the net deferred tax asset and (liability) recognized are as follows:
At December 31, 2001, the Company had Federal net operating loss carry forwards of approximately $12,651,100 which expire in the years 2012 through 2021. The Company has California net operating loss carry forwards at December 31, 2001 of $6,564,029 which begin to expire in 2007.
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.
10. OTHER:
Related Party Transactions - For the years ended December 31, 1999 a director of the Company was paid $75,000 pursuant to a consulting contract for management and geologic evaluation services. In addition, the director subscribed to 350,000 shares of the Company's common stock at a price of $0.05 per share ("founder shares"). The Director became an employee of the Company effective January 2000.
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.
Employment Contracts- The Company has executed an employment contract dated June 23, 1997 with its president who also serves as a director. The contract provides 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. The contract may be terminated by the Company without cause upon the payment of any of the following:
(a) Options to acquire the common stock of the Company in an amount equal to 10% of the then issued and outstanding shares containing a five year term, piggyback registration rights and an exercise price equal to 60% of the fair market value of the shares during the sixty day period of time preceding the termination notice, such amount not to exceed $3.00 per share.
(b) A cash payment equal to two times the aggregate annual compensation.
(c) In the event of termination without cause, all unvested securities issued by the Company to the Employee shall immediately vest and the Company shall not have the right to terminate or otherwise cancel any securities issued by the Company to the Employee.
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, 200 1, 2000 and 1999 was $31,377, $15,456 and $4,693, respectively.
11. OTHER ASSETS:
Other assets of approximately $1,472,570 and $746,140 at December 31, 2001 and December 31, 2000, respectively, consisted primarily of unapplied well prepayments.
12. NET INCOME (LOSS) PER COMMON SHARE:
The following represents the calculation of net income (loss) per common share:
The following common stock equivalents were not included in the computation for diluted earnings (loss) per share because their effects were antidilutive.
Common Stock Equivalents: Shares ---------------------------------------- ----------
Options 43,848 Warrants 287,589 "As-if" conversion of Preferred stock 311,610 ---------- 643,047 ==========
13. SUBSEQUENT EVENTS:
Subsequent to December 31, 2001, the Company entered into the following commodity price hedging contracts as set forth below with respect to a portion of its natural gas and crude oil production for 2002 and 2003. 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.
Natural Gas: NYMEX Contract Price per MMBtu --------------------------------- Volume in Collars Period MMBtus Floor Ceiling
March 02 - Feb 03 1,460,000 $2.30 $2.91
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. Based on the Company's production rate at December 31, 2001, this represents approximately 53% of the Company's natural gas production.
Crude Oil: NYMEX Contract Price per Barrel --------------------------------- Volume in Collars Period Barrels Floor Ceiling
April 02- Mar 03 60,000 $20.50 $21.75
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. Based on the Company's production rate at December 31, 2001, this represents approximately 43% of the Company's crude oil production.
14. 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 those 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, 2001, the Company's proved oil and gas reserve 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, 2001, 2000 and 1999:
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 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, 2001, 2000 and 1999 based on the standardized measure prescribed in Statement of Financial Accounting Standard No. 69:
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, 2001, 2000 and 1999:
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 30th day of March, 2001.
BETA OIL & GAS, INC.
Date: March 28, 2002 By: /s/ Steve A. Antry --------------------------- Steve A. Antry Chairman of the Board of Directors 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.
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)
10.14BWC 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).
10.19Redfish 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)
10.24Northeast 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)
10.25Sarah 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).
10.29Mushroom 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).
10.30Starboard 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).
10.31First 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).
10.32First 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).
10.33Second 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).
10.34Third 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).
10.35Form 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.
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 28, 2002
23.3 Consent of Ryder Scott and Associates dated March 28, 2002
99 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).