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. The Company is a Nevada corporation and was 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 Wyoming.
At December 31, 2000, we owned interests in approximately 275 gross wells, 168 wells net to our interest, in the Mid-Continent, Texas and Louisiana regions and over 18,000 net acres located in these same areas for future exploration. In September 2000, the Company merged with Red River Energy, Inc., ("RRE") (See Oklahoma under this item) which operates and owns an interest in producing properties in Oklahoma, Kansas and Texas. Additionally, the Company participated in drilling and completion of 21 gross wells for the year.
At December 31, the Company's oil and gas properties had net proved reserves of 24.3 BcfEQ, comprised of 19.4 Bcf of natural gas and 814 MBbl of oil. From the first quarter of 1999 through the fourth quarter of 2000, we have increased our average net daily production from 205 McfEQ of natural gas to 8,729.2 McfEQ of natural gas.
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, Louisiana and more recently the Wind River Basin of Wyoming.
Following the 2000 acquisition of RRE, we have a base production level in place that can provide consistent cash flow to assist with 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 targets by minimizing and diversifying our ownership positions. We utilize economical and 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. 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. This has reduced general and administrative costs necessary to conduct operations.
Current Projects TEXAS Approximately $12.3 million has been expended to date to acquire working interests in lands and seismic data 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 17 discoveries out of 22 wells drilled for a 75% success rate. During the year 2000, 12 exploratory wells were drilled which resulted in nine discoveries. Additionally, the leasing of acreage covering 12 deeper Wilcox prospects generated by Beta is near completion.
In 2000, we also added three more potentially high impact Texas prospects - Brookshire Dome project in Waller County, Texas, Detroit prospect in Red River County, Texas and Greens Lake prospect in Galveston County, Texas. In the last half of 2000, we participated in the drilling of three wells, two shallow and one deep, in the Brookshire Dome project.
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 project. Most of the portion 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 45,000 acres are currently under lease for drilling.
From the 3-D seismic survey data, we identified over 100 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 our 300 square miles. Since 1997, 152 wells had been drilled in the area with over an 80% success rate. Of particular interest to us was that, of this group, over 40 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 1 TCF (trillion cubic feet) of natural gas. We identified 12 Wilcox prospects in the trend, and will commence drilling in the last of half of 2001. We will have an average 20% or less working interest in these prospects and most likely will not be the operator.
We presently own working interests in four Onshore Gulf Coast exploration projects located in Jackson County, Texas. Approximately 26,607 gross acres, approximately 6,606 acres net to our working interest, of oil and gas leases have been acquired in these four projects as of December 31, 2000. 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 virgin fault segments in compartmentalized fields.
We believe this to be one of the best trends in the onshore Gulf Coast, and consider it an impressive feat to have this much acreage for a proprietary 3-D seismic survey. Given the drilling success rates in this trend, and the increase in commodity prices, we would find it more difficult to acquire our interest in the area today. We believe this project provides low 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 Brookshire Dome and Jackson County wells is approximately 2,600 McfEQ of natural gas. The status of the projects is as follows:
a.) Texana Project. Approximately 25,000 gross acres under seismic coverage; 7,972 gross acres under lease; 1,993 acres under lease net to Beta's 25% working interest as of December 31, 2000: 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 16 potential locations, ten Frio/Yegua and six Wilcox, have been identified for drilling in future periods. Drilling commenced in late 2000 and the first exploratory well is currently being evaluated and a second exploratory well has been drilled, awaiting completion. The Yegua formation was the primary objective in both wells.
b.) Formosa Grande Project. Approximately 92,000 gross acres under seismic coverage; 8,308 gross acres under lease; 2,077 acres under lease net to Beta's 25% working interest at December 31, 2000: Approximately 140 square miles of 3-D seismic data has been acquired. The seismic data has been interpreted and prospects identified. Approximately 29 potential locations, 27 Frio and 2 Miocene, have been identified for drilling in future periods.
Four exploratory wells were drilled in 2000, two were discoveries and two were dry holes. Subsequent to December 31, 2000, three additional exploratory wells were drilled resulting in two discoveries and one dry hole. All wells drilled to date targeted the Frio formation. Of the four discoveries, three are collectively producing over 3,000 Mcf per day. The fourth well is awaiting connection to the pipeline. Presently, one exploratory well is drilling.
c.) Ganado Project. Approximately 25,000 gross acres under seismic coverage, 466 gross acres under lease; 95 acres under lease net to Beta's 20% working interest at December 31, 2000: Approximately 40 square miles of 3-D seismic data has been acquired and is in the interpretive stages. Approximately 39 additional locations, 38 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 discoveries and two dry holes. In 2000, two wells, one exploratory and one development, were drilled and completed as producers. Subsequent to December 31, 2000, one additional exploratory well was drilled and completed as a producer. Of the three recent discoveries, two wells are currently producing an average of 2,000 Mcf of gas and 40 Bbl of crude oil per day. The third and most recent discovery is producing approximately 200 Mcf per day.
d.) BWC Project. Approximately 42,440 gross acres under seismic coverage, 8,480 gross acres under lease; 1,060 acres under lease net to Beta's 12.5% working interest at December 31, 2000: Approximately 66 square miles of 3-D seismic data has been acquired and is in the interpretive stage. Six exploratory wells were drilled in 2000 resulting in five discoveries and one dry hole. A total of eleven exploratory wells have been drilled in this project area with only one dry hole resulting in a 90% success rate. Subsequent to December 31, 2000, one exploratory well was drilled and was a dry hole and a second exploratory well is currently drilling. An additional exploratory well is scheduled to spud in early second quarter 2001. The five discovery wells are currently producing an average of 600 Mcf of natural gas per day.
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. Approximately 105 prospects, 99 Frio/Yegua and 6 Wilcox/Queens City, in total have been identified for future drilling in this project.
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 25% in this project. This well is scheduled in the second half of 2001 for drilling.
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:
o 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.
o 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).
o 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 and 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.
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 25% 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. Two prospects have been delineated within this project area, the Sara White Prospect (to the south) and the N.E. Hitchcock Prospect (to the north).
The current strategy is to drill the lower risk Sara White in mid-2001 to establish potential production and proved reserves before testing the deeper Vicksburg potential.
The Brookshire Dome Project We have a joint exploration agreement with Prime Natural Resources, Inc. to explore and exploit oil and gas potential associated with the Brookshire Shallow Piercement Salt Dome located approximately 30 miles west of Houston, Texas. We have a 25% WI in the project.
This salt dome had been considered barren of economic reserves due to an interpreted late growth history of the salt dome structure. However, a seismic line shot in 1982, which was recently reprocessed with state of the art technology, suggested the possibility of sediments at depths of 4,000' to 7,000' below a salt overhang. Additional high technology interpretation of gravity data in conjunction with the seismic and a surface geochemical survey further supported this concept.
We have leased approximately 2,000 acres, 245 net acres, which are favorably located to test sands that may lie in a hydrocarbon trapping position below the salt. 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.
In 2000, we drilled a 3,200' test well in the shallow productive trend extending onto our block, which was successful and possesses three oil sands. Subsequent to December 31, 2000, the well was completed as a dual producer and had an initial production test of approximately 300 Bbls per day. A second well has been drilled and is waiting on completion. Based upon present subsurface interpretation, we could possibly participate in approximately 25 wells in the shallow play. We also have a small farmout interest in three oil wells, which were drilled in 2000 and are located south of the main acreage block. Two of these wells are currently producing an average of 200 Bbls per day and the third well is waiting on the production facility.
An additional deeper 7,500' Yegua test well was drilled in 2000 and resulted in a dry hole. A 3-D seismic survey is being planned to cover our controlled acreage, approximately 3,000 acres, and should be completed mid-2001. This survey should more efficiently guide the development of this field. We believe there is significant potential in the prospect area for production from the Yegua and Wilcox formations located at approximately 9,000 feet and presently have plans to drill an additional test well in the last half of 2001.
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 of sands. An initial well will be drilled in the last half of 2001 to approximately 16,000 feet with a dry hole cost net to our interest of approximately $750,000. We plan to operate the project with a 25% working interest.
LOUISIANA Beta has invested approximately $9.3 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. In mid-2000, we commenced drilling a Duvall test well in the Lapeyrouse project which was completed as a discovery subsequent to December 31, 2000. Also during the year, we initially participated in the drilling of the Shark Deep prospect, which is operated by Gryphon Exploration (formerly Cheniere Energy, Inc.). However, due to a substantial cost overrun in the drilling phase and a projected marginal rate of return for the well, we elected to go non-consent in the completion phase of this well. The Company also had participation rights in acreage acquired and wells drilled in the West Cameron Block 39 under an expired exploration agreement with Rozell Energy. There were three potential deeper prospects in which the Company could have participated but declined. We expect to participate in drilling a minimum of two wells in Louisiana during 2001. At present our net daily average production in the Transition area of Louisiana is approximately 1,000 McfEQ of natural gas.
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 commenced drilling in 2000 and was successfully completed in the first quarter of 2001. The TC#1 tested at 10.8 Mmcf per day and 400 Bbl of oil per day from the Duvall formation and is expected to commence sales by mid-2001. Two more wells are planned for the last half of 2001.
The Lafourche Parish Project One of our most anticipated projects is a prospect located in Lafourche Parish, Louisiana, where we hold a working interest of approximately 7.5%. The prospect consists 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 initial well test will be drilled to approximately 17,500 feet during the second quarter of 2001 with a dry hole net cost to our interest of approximately $300,000 and a completed cost of approximately $400,000.
OKLAHOMA In September 2000, we acquired 100% interest in RRE as per the previously reported Agreement and Plan of Merger (Merger). The Company 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. Located 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 Oil And Gas Operations. Presently the net daily average production for these properties is approximately 5,300 McfEQ of natural gas.
In June 2000, previous to the Merger, RRE 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 includes 34 (30 net) operated oil wells, 3 (2 net) operated gas wells, 30 (4 net) non-operated oil wells and 44 (7 net) non-operated gas wells. In total 74 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 Merger 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, 2000, WEHLU had proven reserves of approximately 12.3 BCFEQ or approximately 51% of the total proven reserves for the Company. WEHLU currently produces approximately 3,460 McfEQ per day.
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. In 2000, RRE agreed 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 in the pilot program and have not produced the results expected. However, this does not condemn the program and Avalon is evaluating another area of the field for additional drilling. Under the terms of the agreement, a minimum of four wells and a maximum of eight are to be drilled for the pilot program in the field. WEHLU is a very large field and we are still optimistic that additional oil and gas will be recovered through either this program or developmental drilling.
Concurrent to, and separate from, the joint development with Avalon, we have budgeted for 2001 $1.5 million for a redrill, workovers on existing wellbores and a saltwater disposal in the WEHLU area. We will continue to exploit other development opportunities within this unit.
Charlie Project The Charlie Prospect, coal bed methane properties also acquired in the Merger, has increased production to 500 Mcf per day, a 300 percent increase since acquisition. 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 retired, production was stimulated from existing wells and an additional fifteen wells have been identified for new fracturing stimulation in 2001. At December 31, 2000, this project had approximately 280 Mmcf of proved reserves.
McIntosh County Project We hold approximately 8,480 acres (6,160 net acres) of oil and gas leases and have interests in 45 wells (34 net) and operate 39 of those wells in the Hitchita Field. In 2000, we drilled two successful wells producing with a combined rate of 1.2 Mmcf per day. Subsequent to December 31, 2000, a stepout/extension well was drilled and resulted in a dry hole. In a different prospect area, an exploratory well was drilled and resulted in a discovery and is currently awaiting connection to the pipeline. Six additional wells, both exploratory and discovery, are planned for the remainder of 2001.
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 47 wells, including the wells in which we have an interest. During 2000, our gas gathering system in this area increased throughput from 1.6 Mmcf per day to 2.2 Mmcf per day and had gathering revenues of approximately $320,000. We are actively seeking new well connections with our 2001 goal of increasing the gathering system throughput to approximately 3.0 Mmcf per day.
WYOMING The Madden Field Project Subsequent to December 31, 2000, we purchased a 75% W.I. in fee and federal leases totaling 786 acres within the Madden Field located in Fremont County, Wyoming in the Wind River Basin. This acreage offsets three wells in the Lower Fort Union and Lance formations that have net pay thickness of 1,090' to the south, 660' to the east, and 978' to the west. In addition, we have options on 5,700 acres in the North Madden Area to the north and 5,200 acres in the Birdseye Creek Area to the northwest. Our immediate objective is to develop the L. Fort Union at a depth of approximately 8,700' and the Lance at a depth of approximately 15,000'. The first well is planned for drilling in summer 2001.
INTERNATIONAL Australia We are currently active in one prospect area located in West Queensland, Australia and is located on the Ethabuka structure. The projected drilling of a well would be an offset to a well drilled in the 1970's but was abandoned due to drilling difficulties. If this well is drilled, it would not take place until late 2001.
Summary of Oil and Gas Operations
Capitalized costs at December 31, 2000, and 1999 relating to our oil and gas activities are summarized as follows:
December 31, 2000 December 31, 1999 United States ......... Foreign United States Foreign Capitalized costs- Evaluated properties .............$ 41,429,542 $ 1,680,921 $ 8,128,928 $ 1,681,270 Unevaluated properties ..............13,326,778 123,569 11,973,532 118,095 Less- Accumulated depreciation, depletion, amortization and impairment (4,673,635) (1,681,270) (2,115,957) (1,681,270) ------------ ------------ ------------ ------------ $ 50,082,685 $ 123,220 $ 17,986,503 $ 118,095 ============ ============ ============ ============
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, 2000 and 1999 represent property acquisition and exploration costs in connection with our Louisiana, Texas and Oklahoma prospects. The prospects and their related costs in unevaluated properties have been assessed individually and no impairment charges were considered necessary for the United States properties for any of the periods presented. The current status of these prospects is that seismic has been acquired, processed and is currently being interpreted on the subject lands within the prospects. Drilling commenced on the prospects in the first quarter of 1999. 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 where they will be subject to amortization.
Unevaluated oil and gas properties - Foreign
Unevaluated costs as of December 31, 2000, outside the United States represent costs in connection with the evaluation and proposed acquisition of one or more exploration blocks in Australia.
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. Total cost in evaluated properties did not exceed their net realizable value at December 31, 2000. During the year ended December 31, 2000 we participated in the drilling of 21wells within the United States. At December 31, 2000, evaluated property cost was $41,429,542 which included $28,371,531 associated with the RRE Merger. No impairment was recorded for 2000. It was determined that the total costs in evaluated properties of $8,128,928 as of December 31, 1999 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 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 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, 2000. We have not included in the table, acreage in which our interest is limited to options to acquire leasehold interests, royalty or similar interests.
Producing Wells Acreage ---------------------------------------------- --------------------------------------------------------- Oil Gas Developed Undeveloped Gross Net (1) Gross Net (1) Gross Net (2) Gross Net ------- --------- -------- --------- ----------- ----------- ----------- -----------
Texas 8 .66 44 7.21 22,827.3 1,373.3 37,724.7 14,379.8 Oklahoma 80 58.39 115 79.39 54,320.9 42,051.5 2,860.5 2,804.4 Louisiana - - 6 .74 7,573.9 854.8 9,250.6 598.9 Kansas 19 18.79 2 2.00 6,889.5 3,681.1 640.0 640.0 California - - 1 .30 318.0 95.6 - - ------- --------- -------- --------- ----------- ----------- ----------- ----------- 107 77.84 168 89.64 91,929.6 48,056.3 50,475.8 18,423.1 ======= ========= ======== ========= =========== =========== =========== ===========
(1) Net wells are computed by multiplying the number of gross wells by our working interest in the gross wells. (2) Net acres are computed by multiplying the number of gross acres by our working interest in the gross acres.
At December 31, 2000, approximately 10,138 gross acres and 4,279 net acres will expire in 2001.
In addition to the interests we own in developed and undeveloped acreage, at December 31, 2000 we have an option, which expires April 16, 2002 to acquire interest in an additional 10,032 gross (3,344 net) acres in Jackson County, Texas.
OIL AND NATURAL GAS RESERVES At December 31, 2000, we had proved reserves of 814.0 Mbbls of oil and 19.4 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, 2000, the present value of our future net revenues (revenues less production and development cost) before income taxes attributable to these reserves.
Proved Proved Developed Undeveloped Total Proved ---------------- ---------------- ------------------- Oil (Bbls) - 813,970 813,970 Gas (Mcf) 19,115,000 303,000 19,418,000
Future Net Revenues (before income taxes) $ 172,269,015 $ 2,318,800 $ 174,587,815 ================ ================ ===================
Present value of Future Net Revenue (before income taxes) $ 98,759,975 $ 1,439,313 $ 100,199,288 ================ ================ ===================
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 the Company's McIntosh gathering system, which were $7,736,205 and $4,679,377, 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 be produced. 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 $26.80/Bbl and $9.23/Mbtu at December 31, 2000. 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 2000.
DRILLING ACTIVITY For the period indicated, the following table sets forth the results of our drilling activities in the fiscal years ended December 31, 2000, 1999 and 1998:
Years Ended December 31, -------------------------------------------------------------------------- 2000 1999 1998 Gross Net Gross Net Gross Net -------- -------- --------- ---------- --------- --------- Exploratory: Productive 14 2.24 12 1.75 2 .84 Dry 5 1.13 9 2.42 6 1.13 -------- -------- --------- ---------- --------- --------- Total Exploratory 19 3.37 21 4.17 8 1.97 Development: Productive 2 .26 - - - - Dry - - - - - - -------- -------- --------- ---------- --------- --------- Total Development 2 .26 - - - - Total: Productive 16 2.50 12 1.75 2 .84 Dry 5 1.13 9 2.42 6 1.13 9 -------- -------- --------- ---------- --------- --------- Total 21 3.63 21 4.17 8 1.97 ======== ======== ========= ========== ========= =========
Subsequent to December 31, 2000, we have drilled 10 gross exploratory wells, 2 net wells, of which 7 gross wells, 1.3 net wells were discoveries and 3 gross wells, .6 net wells, were dry holes. Currently 5 gross wells, .9 net wells, are drilling or waiting on 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, ------------------------------------- 2000 1999 ----------------- ---------------
Oil production (Bbl) 32,617 1,822 Gas production (Mcf) 1,726,416 475,065 Average sales price: Oil (per Bbl) $ 30.57 $ 23.03 $ $ Gas (per Mcf) $ 4.08 $ 2.44 Average production cost per McfEQ $ .71 $ 0.17
Reflects the impact of gas hedge which reduced our 2000 total average gas price per Mcf by $ .27.
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.
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. Should the litigation be resolved adversely to Beta, the net impact to Beta is estimated to be as of March 31, 2001 approximately $250,000 plus costs and litigation expense, if recoupment from various other working interest owners in the affected oil and gas properties is successful. If Beta is unable to recoup such damages, the net adverse impact to Beta is estimated to be approximately $550,000 plus costs and litigation expense.
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, 2000.
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 1999 and the 1st quarter of 2000 and the Nasdaq National Market for the remaining three quarters of 2000. 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, except as noted in "Item 13. Certain Relationships and Related Transactions - Subsequent Events" regarding our preferred stock for use in the expansion of our business.
2000 High Low ---- ---- --- 1st Quarter.......... $ 10.5625 $ 6.5312 2nd Quarter.......... 10.8750 7.7500 3rd Quarter.......... 12.0000 7.7500 4th Quarter.......... 9.3750 6.8125
1st Quarter.......... N/A N/A 2nd Quarter.......... N/A N/A 3rd Quarter.......... 6.6875 4.2500 4th Quarter.......... 8.6250 5.9375
Approximately 271 shareholders of record and approximately 1,978 beneficial owners as of March 15, 2001 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.
Recent Sales of Unregistered Securities We issued and sold the following securities without registration under the Securities Act of 1933, as amended ("Securities Act"), for the quarter ended December 31, 2000:
1. On October 1, 2000 we issued 50,000 shares upon the exercise of warrants to purchase common stock to an outside director. The certificates representing the shares issued bear a restrictive legend prohibiting transfer without registration under the Securities Act or the availability of an exemption from registration and "stop transfer" instructions were issued to the transfer agent.
2. On October 15, 2000 we issued 60,000 shares upon the exercise of warrants to purchase common stock to an outside broker for services rendered. The certificates representing the shares issued bear a restrictive legend prohibiting transfer without registration under the Securities Act or the availability of an exemption from registration and "stop transfer" instructions were issued to the transfer agent. The shares have since been rescinded.
3. On October 16, 2000 we issued 15,000 shares upon the exercise of warrants to purchase common stock to an outside broker for services rendered. The certificates representing the shares issued bear a restrictive legend prohibiting transfer without registration under the Securities Act or the availability of an exemption from registration and "stop transfer" instructions were issued to the transfer agent.
4. On December 8, 2000 we issued 135,000 shares upon the exercise of options to purchase common stock pursuant to a 1999 Incentive and Nonstatutory Stock Option Plan for our employees. The certificate representing the shares bear a restrictive legend prohibiting transfer without registration under the Securities Act or the availability of an exemption from registration and "stop transfer" instructions were issued to the transfer agent.
In connection with the issuance of the above noted securities, we relied upon Section 4(2) of the Securities Act in claiming exemption for the registration requirement of the Securities Act. All of the persons to whom the securities were issued were sophisticated persons who had full information concerning our business affairs and each acquired the shares for investment purposes. The certificates representing the shares issued bear a restrictive legend prohibiting transfer without registration under the Securities Act or the availability of an exemption from registration. "Stop transfer" instructions were issued to the transfer agent.
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 RRE in 2000 affected the comparability between the Financial Data for the periods presented.
For the years ended December 31, The period from inception (June 6, 1997) through December 31, 1997
2000 1999 1998 --------------- --------------- --------------
Income Statement Data: Operating revenues ....... $ 8,357,867 $ 1,199,480 $ -- $ -- Operating expense ........ 1,516,113 81,538 -- -- General and administrative 2,141,005 1,418,240 746,769 245,452 Impairment expense ....... -- 1,224,962 1,670,691 -- Depreciation and depletion expense ....... 2,693,439 914,233 11,883 1,530 Interest expense ......... 393,008 2,966,651 -- -- Net income (loss) ........ 1,425,565 (5,384,403) (2,384,500) (201,573)
Earnings (loss) per share: Basic .................... $ .134 $ (.66) $ (.37) $ (.05) Diluted .126 (.66) (.37) (.05)
Weighted average common shares and equivalent outstanding: Basic .................... 10,616,692 8,160,000 6,366,923 4,172,662 Diluted .................. 11,281,413 8,160,000 6,366,923 4,172,662
Balance sheet data: Working capital ................... $ 3,533,237 $ 2,034,268 $ (96,457) $ 3,117,351 Total assets ...................... 58,466,152 20,881,475 13,618,471 9,921,057 Total long term debt .............. 13,814,034 27,939 -- -- Stockholder's equity .............. 40,060,406 20,588,237 13,299,342 9,050,210
Proved Reserves Oil (Mbbls) 814.0 13.2 1.4 -- Gas (Mmcf) ................... 19,418.0 4,170.0 1,596.7 -- Total (Mmcfe) ................ 24,302.0 4,249.2 1,605.1 --
Present value of estimate future net revenues before income tax discounted at 10% ................. $ 100,199,288 $ 6,012,972 $ 1,716,608 $ --
SELECTED QUARTERLY ....... For the quarter ended FINANCIAL DATA
(In Thousands of Dollars) March 31 June 30 September 30 December 31 -------- ---------- -------- ---------
Revenues ................. $ 940.3 $ 1,082.3 $ 2,022.8 $ 4,312.5 Operating income (loss) 906.4 959.8 1,689.5 3,286.1 Net income (loss) ........ (125.4) (50.5) 840.4 761.1 Earnings (loss) per share: Basic ............... (0.01) (0.01) 0.08 0.06 Diluted ............ (0.01) (0.01) 0.07 0.06
Revenues ................. $ 29.7 91.6 254.3 $ 823.9 Revenue - LOE ............ 20.7 88.7 242.1 766.44 Net income (loss) ........ (714.1) (1,078.2) (1,851.5) (1,740.6)
Earnings (loss) per share: Basic ............... (0.10) (0.14) (0.21) (0.21) Diluted ............. (0.10) (0.14) (0.21) (0.21)
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, 2000 and 1999, and the results of operations for the years ended December 31, 2000, 1999 and 1998.
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 come from internally generated cash flow from operations, funds generated from the exercise of warrants and our initial public offering.
Our working capital was a surplus of $3,533,237 at December 31, 2000 compared to a surplus of $2,034,268 at December 31, 1999 and a deficit of ($96,457) at December 31, 1998. Our working capital increased primarily due to a positive cash flow from operations during the year 2000, funds received from the exercise of common stock purchase warrants and the Merger (See Item 8. Financial Statements, Note 2. Acquisitions And Oil And Gas Operations.) One major factor in our increased cash flow from operations has been the upward trend in the price received for crude oil and natural gas in 2000. To date, a significant amount of working capital has been used in our exploration and development program.
The following table represents the sources and uses of cash for the years indicated.
For the years ended December 31, 2000 1999 1998 --------------- ------------- -------------- Beginning cash balance $ 1,448,655 $ 198,043 $ 3,985,599 Sources of cash: Cash provided by operations 3,229,081 (1,262,655) (1,215,673) Cash provided by financing activities 2,900,170 9,759,960 6,525,108 Cash provided from merger 895,097 - - --------------- ------------- -------------- Total sources of cash including cash on 8,473,003 8,695,348 9,295,034 hand Uses of cash: Oil and gas expenditures (6,666,327) (6,945,695) (8,928,201) Other assets (including advance to industry partners) (270,490) (300,998) (168,790) --------------- ------------- -------------- Total uses of cash (6,936,817) (7,246,693) (9,096,991) --------------- ------------- -------------- Ending cash balance $ 1,536,186 $ 1,448,655 $ 198,043 =============== ============= ==============
For the year ended December 31, 2000, funds on hand and net funds received from operations and from the exercise of warrants were sufficient to meet our capital requirements. We received approximately $3,205,000 from the exercise of warrants. Cash flow from operations increased significantly for the year from increased production volume and natural gas prices. This will be discussed in detail in "Comparison of Results of Operations for the Years Ended December 31, 2000 and 1999."
During the year we expended approximately $6.3 million to fund the drilling of its exploratory prospects, development of existing properties and acquisition of additional acreage. This included: $2.4 million for the drilling of 13 wells (9 were completed, 3 were dry holes and 1 is in evaluation process) in our Jackson County, Texas prospects, $1.0 million on the leasing and drilling of the Shark Deep prospect in which we went non-consent on the completion, $.5 million drilling and lease costs related to our Lafourche Parish, Louisiana TC#1 well, $.5 million for drilling and completion of three wells in the Brookshire Dome prospect, $.5 million in development and facilities located in the West Cameron Block 39 and 49 leases, offshore Louisiana, $.3 million in drilling costs related to our Northern California prospect which were subsequently abandoned due to depletion, $.6 million in lease acquisition costs on our North Texas prospect and $.3 million related to development cost in the WEHLU unit in Oklahoma.
During the year ended December 31, 1999 we realized net proceeds of $2,835,000 from a bridge note financing, net proceeds of $7,733,553 from public offering and net proceeds of $2,052,620 from exercise of Beta common stock warrants. The combination of these proceeds funded our capital requirements for the year. We issued promissory notes having a maturity date of one year and bearing an interest rate of 10%. In addition, a total of 459,000 shares of our common stock were issued in connection with the 1999 bridge financing. Our bridge notes were repaid in full with accrued interest on July 7, 1999 from the proceeds of our initial public offering. The estimated fair market value of 429,000 shares of common stock issued in connection with the bridge note of $2,754,000 was treated as a discount and was amortized over the term of the promissory note 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 1999. Accordingly, we 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 1999.
We financed all of our business activities in December 31, 1998 through issuances of our common stock in private placements. We raised net proceeds of $6,548,632 during 1998 from a private placement.
Plan of Operation for 2001 For the year 2001, we expect to fund our capital requirements from existing working capital, net cash flow from operations (after general and administrative expense), and the exercise of common stock purchase warrants. We are planning to raise additional funds through a private placement offering convertible preferred stock. We expect the private placement to take place early in the second quarter of 2001.
Our projected 2001 capital expenditures are as follows:
o $8 million for drilling and completion costs associated with our South Texas and Louisiana prospects o $2 million associated with drilling, completion and workovers in the Mid-Continent Region. $1.5 million is for a salt water disposal well and a redrill project for the WEHLU unit. o $4 million for the exploration of a prospect located in the Wind River Basin, Wyoming. We acquired this prospect in the first quarter of 2001 with management reviewing the prospect potential since December 2000 o $1 million for leasehold acquisition and seismic
As with any projection, the timing and amounts can vary. The timing for drilling wells has been more difficult to estimate due to drilling rig availability. Generally, funds must be advanced within thirty days or less after our election to participate.
Our planned capital expenditures and administrative expenses could exceed those amounts budgeted and could exceed our cash from all sources. Due to the volatility of the natural gas and crude oil prices, while our capital expenditures are on budget we could see a significant short fall from cash flow from operations should these prices decrease. If this happens, it may be necessary for us to raise additional funds. It is anticipated that additional funds could be raised from one or more of the following sources:
1) We have approximately 375,725 callable common stock purchase warrants outstanding exercisable at a price of $7.50 per share. We are able to call these warrants at any time after our common stock has traded on Nasdaq at a market price equal to or exceeding $10.00 per share for 10 consecutive days which was achieved in July 2000. It is our intent to call all of these warrants at such time, if and when, the cash is needed to fund capital requirements. We will receive proceeds equal to the exercise price times the number of shares which are issued from the exercise of warrants net of commission to the broker of record, if any. We could realize net proceeds of approximately $2,814,500 from the exercise of all of these warrants. There is no assurance that any warrants will be exercised or that we will ever realize any proceeds from the $7.50 warrant calls.
2) We currently have approximately $500,000 of available borrowing capacity under our revolving credit facility.
3) 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.
4) 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. We currently estimate that during 2001 the wells will generate approximately $16 million of net cash flow after deducting lease operating expenses of approximately $4 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.
Our long term goal is to continue the pattern of growing the Company by accumulating oil and gas reserves through acquisition and drilling during the next three to five year period, and then selling the Company. In the event we cannot raise additional capital, or the industry market is unfavorable, we may have to slow or alter our long-term goal accordingly.
These are forward looking statements that are based on assumptions, which in the future may not prove to be accurate. Although we believe that the expectations reflected in such forward looking statements are based on reasonable assumptions, we can give no assurance that our expectations will be achieved.
Long Term Liquidity and Capital Resources The timing of most of our capital expenditures is discretionary. 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 experience on planned exploratory drilling activities in future periods, gas and oil price conditions and other related economic factors. Accordingly, we have not prepared an estimate of capital expenditures for future periods beyond 2001.
Comparison of Results of Operations 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.
In Thousands ................................... Years Ended December 31, $ - Increase % - Increase 2000 1999 (Decrease) (Decrease) ------------------------------------------------ -------- -------- --------------- -----------
Net income (loss) .............................. $ 1,425.6 $ (5,384.4) $ 6,810.0 126% Oil and gas sales .............................. 8,037.2 1,199.5 6,837.7 570% Field service income ........................... 320.6 -- 320.6 100% Operating expense .............................. 1,516.1 81.5 1,434.6 1760% G"&"A expense 2,141.0 1,418.2 722.8 51% Depletion and Depreciation ..................... 2,693.4 914.2 1,779.2 195% Impairment expense -- 1,225.0 (1,225.0) -100% Interest expense 393.0 2,966.7 (2,573.7) -87% Income tax provision ........................... 294.3 -- 294.3 100%
Production: Natural Gas - Mcf .............................. 1,726.4 475.1 1,251.3 263% Crude Oil - Bbl ................................ 32.6 1.8 30.8 1711%
Natural Gas Equivalent - Mcfe .................. 1,922.1 486.0 1,436.1 295%
$ per unit: Ave gas price - Mcf ............................ $ 4.08 $ 2.44 $ 1.64 67% Ave oil price - Bbl 30.57 23.04 7.53 33% Ave operating expense - McfEQ .................. .71 0.17 0.54 318% Ave G"&"A - McfEQ 1.12 2.92 (1.80) -62% Ave Depl. and Depr. - McfEQ 1.40 1.88 (0.48) -26%
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 Merger. 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 realized by the Company 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 $1,434,600, or 1760%, to $1,516,100 for the year ended 2000. The increased expenses were due to approximately $1,000,000 of additional operating expenses associated with the Merger 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 Merger 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 Merger 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.
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 Merger, 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 $1,779,200, 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 Merger 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:
Cash interest expense $ 120,555 Amortization of note discount and fair market value of 459,000 shares 2,754,000 Amortization of deferred loan costs 89,100 --------------- Bridge note interest expense for the year ended December 31, 1999 $ 2,963,655 ===============
The decrease was partially offset by the interest expense we incurred in 2000 as a result of debt acquired in the Merger.
Year Ended December 31, 1999 and Compared to Year Ended December 31, 1998 Net loss for the year ended December 31, 1999 was $(5,384,403) compared to $(2,384,500) for the year ended December 31, 1998. The increase in net loss was primarily due to the interest expense related to the bridge note.
Loss from operations totaled $(2,439,493) for the year ended December 31, 1999 compared to $(2,429,343) for the year ended December 31, 1998. During the year ended December 31, 1999 we had oil and gas revenues of $1,199,480. Our net production was 475,065 mcf at an average price of $2.44 per mcf and 1,822 barrels of oil at an average price of $23.03 per barrel. During the year ended December 31, 1998 we generated no revenues. During the year ended December 31, 1999 we incurred lease operating expenses of $81,538. Our average lifting cost for this period was $.17 per mcf equivalent. During the year ended December 31, 1998 we incurred no lease operating expense. General and administrative expenses for the year ended December 31, 1999 were $1,418,240 compared to $746,769 for the year ended December 31, 1998. This represents a $671,471 or a 90% increase over the prior year period. The primary reasons for the increase were due to: o An increase in operational activities in 1999 versus 1998; o An increase in the number of employees from five in 1998 to six in 1999; and o General and administrative costs incurred in 1999 related to our initial public offering and registration statement which are not readily identifiable as offering costs.
Impairment expense for the year ended 1999 was $1,224,962 compared to $1,670,691 for the 1998 year. The impairments for both years are as follows:
1998 1999 Total ---- ---- -----
Foreign cost pool $ 1,624,218 $ 57,052 $ 1,681,270 U.S. cost pool 46,473 1,167,910 1,214,383 ------------- ------------ ------------- $ 1,670,691 $ 1,224,962 $ 2,895,653 ============= ============ =============
As of December 31, 1999, it was determined that the total costs in the U.S. evaluated properties cost pool exceeded the full cost ceiling limitation. Accordingly, an impairment write-down of $1,167,910 was recorded for the year ended December 31, 1999. 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 experienced in the fourth quarter of 1999 when the producing zones in the wells began producing large amounts of water in place of gas and oil.
Depreciation and depletion expense for the year ended December 31, 1999 was $914,233 compared to $11,883 for the year ended December 31, 1998. This represents a $902,350 increase over the prior year period. The primary reason for the increase is due to the fact Beta had no oil or gas production in the prior year period that would give rise to depletion expense.
Other income for the year ended December 31, 1999 consisted of interest income in the amount of $21,741. Beta realized $44,843 of interest income for the year 1998. The reason for the decrease was lower average cash and cash equivalents balances for the 1999 period as compared to the 1998 period.
During the year ended December 31, 1999, Beta incurred interest expense of $2,966,651, substantially all of which related to the bridge notes. Interest expense related to the bridge notes for the 1999 period consists of the following:
Cash interest expense $ 120,555 Amortization of note discount and fair market value of 459,000 shares 2,754,000 Amortization of deferred loan costs 89,100 --------------- Bridge note interest expense for the year ended December 31, 1999 $ 2,963,655 ===============
During the year ended December 31, 1998, Beta incurred no interest expense.
Quarter Ended December 31, 2000 and Compared to Quarter Ended September 30, 2000 (Unaudited) Revenues and operating income for the quarter ended December 31, 2000 increased approximately 113% and 94%, respectively, compared to the quarter ended September 30, 2000. The increases were a result of increased production volumes associated with the RRE merger, which was effective September 1, 2000 and additional wells put on production. Our production volume for the quarter ended December 31, 2000 was approximately 803,000 Mcf equivalent compared to approximately 458,800 Mcf equivalent or 75% increase.
Net income for the fourth quarter ended 2000 decreased by approximately 9% from the previous quarter primarily due to increased depletion and depreciation expense, interest expense and income tax expense. Depletion and depreciation expensed for the quarter increased approximately $1.0 million from the quarter ended September 30, 2000 to $1.4 million. Interest expense increased approximately $.3 million from the previous quarter due to RRE outstanding debt. Income tax expense for the quarter ended December 31, 2000 was approximately $.3 million higher than the quarter ended September 30, 2000.
Quarter Ended December 31, 2000 and Compared to Quarter Ended December 31, 1999 (Unaudited) Revenues for the quarter ended December 31, 2000 increased by approximately $3.5 million from December 31, 1999 to $4.3 million. Operating and net income for the quarter ended December 31, 2000 increased approximately $2.5 million from December 31, 1999 to $3.3 million and $.8 million, respectively. The increases were a result of increased production volumes associated with the RRE merger, which was effective September 1, 2000 and additional wells put on production in 2000.
The results for quarter ended December 31, 1999 included an impairment charge for approximately $1.2 million due to downward revisions of reserves associated with wells drilled in 1998. Depletion and depreciation expense for quarter ended December 31, 2000 was approximately $.6 million greater than quarter ended December 31, 2000. The quarter ended December 31, 2000 had interest expense of approximately $.3 million and income tax expense of approximately $.3 million while there was no comparable expense for the same quarter in 1999. Collectively, the increased depreciation and depletion expense, interest expense and income tax expense for the quarter ended December 31, 2000 offset the impairment charge as previously mentioned for December 1999.
Income Taxes As of December 31, 2000, we had available, to reduce future taxable income, a tax net operating loss carryforward of approximately $11,624,000, which expires in the years 2013 through 2020. 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, 2000, we have a deferred liability of approximately $3,526,304.
Impact of Recently Issued Standards In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 (FASB133), "Accounting for Derivative Instruments and Hedging Activities." The FASB has subsequently issued Statement No. 137 and Statement No. 138 which are amendments to FASB133. FASB133, as amended, requires that an entity recognize all derivatives as assets or liabilities in the statement of financial position and measure those instruments at fair value. FASB133, as amended, is effective for fiscal years beginning after June 15, 2000. FASB133, as amended, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. We adopted SFAS133, as amended, beginning January 1, 2001. We do not believe the adoption of FASB133 will have a material impact on our financial position or results of operation.
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. Currently, we have derivative financial instruments in place to mitigate the fluctuations in gas price. The hedged volume represents approximately 22% of our gas equivalent production and is hedged until July 2001. Another 10% of our gas equivalent production was committed to a twelve-month fixed price contract, which was in effect until July 2001. However, in October 2000, we ceased deliveries to the purchaser due to the non-performance of payment. No further deliveries have been made under this contract and said contract is currently in litigation. (See Item 3. Legal Proceedings.) The remainder of our production is not hedged and we may continue to experience wide fluctuations in oil and gas revenues as a result. We are also exposed to market risk related to adverse changes in interest rates. This volatility could be mitigated through the use of financial derivative instruments. Currently, we do not have any derivative financial instruments in place to mitigate this potential risk.
Item 8.
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, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of The Exchange Act The following table sets forth the names and ages of all current directors and executive officers of Beta and the positions in Beta held by them:
Director Name Age Since Position
Steve Antry 45 1997 President, Chairman of the Board, Director
R. Thomas Fetters 61 1997 Managing Director of Exploration, Director
Joe C. Richardson, Jr. 73 1997 Director
John P. Tatum 66 1999 Director
Robert C. Stone, Jr. 51 2000 Director
Joseph L. Burnett 48 Chief Financial Officer since 2000
Stephen L. Fischer 41 Vice President of Capital Markets since 1997
Virginia Cherry 55 Secretary since 2000
Lisa Antry 38 Treasurer since 1997
Directors are elected to serve until the next annual meeting of stockholders and until their successors have been elected and qualified. The Bylaws permit the board itself to fill vacancies and appoint additional directors pending shareholder approval at the next annual meeting. Officers are appointed to serve until the meeting of the Board of Directors following the next annual meeting of stockholders and until their successors have been elected and qualified. Beta's Bylaws currently authorize six directors to serve on the Board of Directors. The last annual meeting of shareholders was held on June 24, 2000.
Steve Antry and Lisa Antry are married.
The business experience of each director, executive officer and key employee is summarized below.
Steve A. Antry, President and Chairman of the Board of Directors, is Beta's founder. In addition, Mr. Antry founded Beta Capital Group, Inc., a financial consulting firm in November 1992, and was its President through June 1997. Beta Capital Group, Inc. specializes in selecting and working with emerging oil and gas exploration companies which have production and drilling prospects strategic for rapid growth yet also need capital and market support to achieve that growth. Most recently, Mr. Antry orchestrated and helped to implement the restructuring of Pease Oil and Gas Company, NASDAQ: WPOG, and remains a Director. Mr. Antry remains Chairman of the Board of Directors of Beta Capital Group, Inc., but resigned as its President to devote his full attention to Beta. Before forming Beta Capital Group, Inc., Mr. Antry was an early officer of Benton Oil "&" Gas Company, NYSE: BNO, from 1989 through 1992, ultimately becoming President of a wholly owned subsidiary. Before Benton, Mr. Antry was a Marketing Director for Swift Energy, NYSE: SFY, from 1987 through 1989. Mr. Antry began working in the oil fields in Oklahoma in 1974. He has served in various exploration management capacities with different companies, including Warren Drilling Company, as Vice President of Exploration and Nerco Oil and Gas, a division of Pacific Power and Light, where he served as Western Regional Land Manager. Mr. Antry is a member of the International Petroleum Association of America "IPAA", serving on the Capital Markets Committee and has B.B.A. and M.B.A. degrees from Texas Christian University.
R. Thomas Fetters, Managing Director of Exploration, and Director, spent 17 years with Exxon ultimately achieving the position of Exploration Planning Manager, Exxon U.S.A. Other notable positions held include Exploration Manager for Exxon Australia "ESSO" and Division Manager of Research in Houston and Chief Geologist, Exxon Production Malaysia. Mr. Fetters was President and Chief Executive Officer of CNG Producing Co. in New Orleans from 1983 through 1989 and President of XCL-China, Ltd. from 1989 through 1995. From 1995 through 1997, he served as Senior Vice President of National Energy Group and also currently sits on the Board of XCL, Ltd.. He earned his B.S./M.S. in Geology from the University of Tennessee in 1966.
Joe C. Richardson, Jr., Director, graduated from Texas A"&"M with B.S. degrees in Petroleum Engineering and Mechanical Engineering in 1950 when he started his career with Shamrock Oil and Gas in Amarillo, Texas. In 1961, Mr. Richardson formed an oil, gas, refining, and compressor equipment fabrication company and, in 1968, co-founded a public oil and gas company that was later merged with Worldwide Energy, Inc. Mr. Richardson has been an officer and/or director of several successful public and private companies including Pyro Energy, Inc. (NYSE), Consolidated Oil "&"Gas (AMEX), Texoil, Inc. (NASDAQ), and Corporate Systems Corporation. He is a Regent Emeritus of the Texas A"&"M University System, past President of the Texas A"&"M Twelfth Man Association, and was honored in 1989 with the University's Distinguished Alumni Award. He currently serves on the University Presidents' Advisory Board and the Engineering Advisory Council. Mr. Richardson is a registered engineer in the state of Texas. The Petroleum Engineering Building on the campus of Texas A"&"M University, completed in 1990, was named in his honor.
John P. Tatum, Director, joined Beta as a director in March 1999. Mr. Tatum has worked in the oil and gas industry since 1962, holding successive positions with Skelly Oil Company, Placid Oil Company, Hunt International Company and Hunt Energy Company. From 1980 to 1996, Mr. Tatum was employed with Triton Energy Corporation as Vice President (1980-82), Senior Vice President (1982-1991) and Executive Vice President (1991-96). As Senior Vice President for Triton Energy Corporation, Mr. Tatum was responsible for directing Triton's operations in Colombia, Thailand, New Zealand, Nepal, Gabor, Cote D'Ivoire and Argentina. Since 1996, Mr. Tatum has worked as an international oil "&" gas consultant. Mr. Tatum received his B.B.A. from the University of Texas in 1956 and conducted graduate studies at the Louisiana State University Graduate Business School.
Robert C. Stone, Jr., Director, joined Beta in September 2000. Mr. Stone's last five years of employment were as Manager of Technical Services, Energy Division, First National Bank of Commerce from 1994 to 1998 (he started with First National as an engineer in 1983) and Manager of Energy Technical Services, Energy/Maritime Division, Hibernia National Bank from 1998 to this year which included evaluation responsibilities for all syndicated and direct lending E"&"P segment clients. Specifically, Mr. Stone concluded or approved all oil and gas collateral evaluations, and developed industry client relationships as well as pricing lending policies. Currently Mr. Stone is the Senior Vice President/Manager of the Energy Group at Whitney National Bank in New Orleans, Louisiana. Mr. Stone began his career as an engineer for approximately eight years with Exxon Company, U.S.A. Mr. Stone holds both a B.S. and M.S. in Engineering from the University of Houston. He was also a Founding Governor of the City Energy Club of New Orleans and is involved with many civic organizations in New Orleans where he still resides.
Joseph L. Burnett, Chief Financial Officer, joined Beta in June 2000. He comes to Beta with 26 years of oil and gas accounting experience and is a CPA. Most recently, Mr. Burnett served American Central Gas Technologies, Inc. as Controller for approximately six years. Prior to American Central, Mr. Burnett served at Esco Energ;y for approximately seven years as Controller and Vice President. Mr. Burnett started his oil and gas career at Skelly Oil (later Getty Oil) in 1974. Mr. Burnett received his Bachelor of Science in Business Administration from Oklahoma State University in 1974.
Stephen L Fischer, Vice President of Capital Markets, has been Vice President of Beta Capital Group, Inc. since March 1996 and from April 1996 through March 1998 he was also a registered representative of Signal Securities, Inc., a registered broker-dealer. Between 1991 and before joining Beta Capital Group, Inc. in 1996, Mr. Fischer was a Registered Representative of Peacock, Hislop, Staley "&" Given, an Arizona based investment banking firm. Since 1983, Mr. Fischer has held various positions in the financial services industry in investment banking, retail, and institutional sales, with a special emphasis on the oil and gas exploration sector.
Lisa Antry, Treasurer, was Executive Vice President of Beta Capital Group, Inc. from July 1994 through June 1997. In June 1997, she was appointed President of Beta Capital Group, Inc. upon the resignation of Mr. Antry. Ms. Antry has in excess of 15 years of finance, accounting, and tax experience. Before Beta Capital Group, Inc., she served as Corporate Planning Manager for United California Savings Bank from 1988 to July 1994. Ms. Antry also served United California for several years as its Finance and Tax Manager and worked at Priority Records, a recording and distribution company, as its Controller. Ms. Antry received her B.B.A. from Stephen F. Austin University in 1984 and her M.B.A. from Pepperdine University in 1991.
Board Committees In 1997 the Board of Directors established an executive committee whose purpose is to formulate and implement recommendations, strategies and actions that are intended to support and protect shareholder value. The executive committee is comprised of three voting members: Steve Antry, Beta's President and Chairman, Tom Fetters, Managing Director of Exploration and Joe C. Richardson, Jr., an independent Director. The Board of Directors implemented these changes to enhance the decision-making processes in aspects of Beta's business when the full board of directors is not readily available. This committee did not meet during 2000.
The Board of Directors also has established an audit committee whose purpose is to oversee Beta's financial reporting and controls and to recommend the appointment of an independent auditor to the board each year. The audit committee is comprised of three voting members: Joe C. Richardson, Jr., John Tatum and Robert C. Stone, Jr., all independent Directors. This committee met once during 2000.
In October 1998, the Board of Directors of Beta established a compensation committee responsible for formulating and recommending to the full Board of Directors the compensation paid to Beta's executive officers. The committee presently consists of two outside Directors, Joe C. Richardson Jr., and John P. Tatum. The compensation committee is discussed in more detail in the section entitled "Executive Compensation." This committee met once during 2000.
Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Securities Exchange Act of 1934 requires our directors, certain officers and holders of 10% or more of Beta's common stock to report to the Securities and Exchange Commission, by a specified date, initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Beta believes that during the fiscal year ended December 31, 2000, its directors and executive officers complied with all these filing requirements, based solely on a review of copies of reports filed under Section 16(a) furnished to Beta and on the written representations of its directors and executive officers.
Item 11.
Item 11. Executive Compensation Summary Compensation Table
The following table will inform you about the compensation earned by Beta's Chief Executive Officer for services rendered to Beta during the fiscal years ended December 31, 1999 and 2000. No other executive officer's cash compensation exceeded $100,000 for the fiscal years ended December 31, 1999 and 2000.
Matching Securities Contributions to Underlying All Other Simple IRA Name and Principal Year Salary Bonus Options/SARs Compensation Retirement Plan Position --------------------------- ------- ----------- --------- ------------------- -------------- -------------------
Steve Antry Chief Executive Officer 2000 $ 150,000 $ 28,552 $ 15,000 (1) $ 75,906 (2) $ 4,500 and Chairman of the 1999 $ 150,000 $ 28,184 $ 25,000 (1) $ 11,250 (2) $ 2,600 Board of Directors 1998 $ 150,000 $ - $ 25,000 (1) $ 9,343 (2) $ -
1. The 25,000 shares of common stock underlying presently exercisable stock warrants were issued March 12, 1998, are exercisable at $5.00 per share and expire on March 12, 2003; the 25,000 shares of common stock underlying stock options were granted January 6, 1999, are exercisable at $6.00 per share and expire on December 31, 2004; and 15,000 shares of common stock underlying stock options were granted on December 8, 2000, are exercisable at $7.70 per share and expire on December 8, 2005. 2. Represents compensation for use of Company leased vehicle and moving allowance related to corporate office move and relocation in July 2000 for Mr. Antry.
Stock Options We use stock options as part of the overall compensation of Directors, officers and employees. We have included summary descriptions of our stock option plans so you can review the types of options we have granted and the significant features of our stock options.
In the following table, we show certain information with respect to stock options granted in 2000 to the named chief executive officer.
Option/SAR Grants in Last Fiscal Year
Individual Grants
Percent of Potential Number of total realizable value securities options/SARs Exercise at assumed annual underlying granted to or base rates of stock Options/ employees price Expiration price appreciation Name SARs granted in fiscal ($/Sh) date for option term # year 5%($)(1) 10%($)(1) ----------------------- -------------- ------------- ---------- -------------- -------------------- Steve Antry 15,000 .08% $7.70 12/8/2005 31,913 70,513
(1) These amounts are calculated based on the indicated annual rates of appreciation and annual compounding from the date of grant to the end of the option term. Actual gains, if any, on stock option exercises are dependent on the future performance of the common stock and overall stock market conditions. There is no assurance that the amounts reflected in this table will be achieved.
The following table shows certain information with respect to stock options exercised in 2000 by Beta's chief executive officer, if any, and the value of his unexercised stock options at December 31, 2000.
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
Number of securities Value of unexercised underlying unexercised in-the-money options/SARs at fiscal options/SARs at the Shares year end (#) fiscal year end ($) acquired on Value Exercisable/ Exercisable/ Name exercise Realized Unexercisable Unexercisable ---------------------- ------------ ------------ ------------------------ ----------------------- Steve Antry None None 65,000 exercisable $ 84,360
(1) The value of in-the-money options is equal to the fair market value of a share of common stock at fiscal year-end ($7.484 per share), based on the last sale price of Beta's common stock, less the exercise price.
Stock Option Plan On September 11, 2000, a majority of our shareholders ratified and approved the adoption of the Company's Amended and Restated 1999 Incentive and Nonstatutory Stock Option Plan previously approved by the board of directors. The plan authorizes the Compensation Committee to grant stock option awards to officers, directors and employees. The plan provides, among other things, the following:
o The maximum number of shares that may be optioned and sold under the plan is 700,000 shares. o The per share exercise price for common shares to be issued pursuant to the exercise of an option shall be no less than the fair market value of Beta's common stock as of the date of grant. o The per share exercise price for common shares to be issued to persons owning more than 10% of the voting stock of Beta at the date of grant, shall be no less than 110% of the fair market value of Beta's common stock as of the date of grant. o The maximum terms of the options shall be a maximum of ten years or such lesser time period as the board of directors determines. The maximum time period for options to be issued to persons owning more than 10% of the voting stock of Beta at the date of grant shall be five years from the date of grant.
The Stock Option Plan provides for the granting to employees of incentive stock options within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended, and for the granting of nonstatutory stock options to directors who are not employees and consultants. In the case of employees who receive incentive stock options that are first exercisable in a particular calendar year whose aggregate fair market value exceeds $100,000, the excess of the $100,000 limitation shall be treated as a nonstatutory stock option under the Stock Option Plan.
The Stock Option Plan is being administered by the Compensation Committee appointed by our board of directors. This committee consists of two directors, Joe C. Richardson, Jr. and John Tatum, neither of who are employees of Beta. As such, under Rule 16b-3, the grant of such stock options under the Stock Option Plan to officers and directors who are our employees is exempt from the short swing profits provisions under Section 16(b) of the Securities Exchange Act of 1934 ("1934 Act").
This committee has the power, subject to the approval of our board of directors, to determine the terms of the options granted, including the number of shares subject to each option, the exercisability and vesting requirements of each option, and the form of consideration payable upon the exercise of such option (i.e., whether cash or exchange of existing shares of Beta common stock in a cashless transaction or a combination thereof).
A maximum of 700,000 shares of Beta common stock (which amount is subject to adjustment for stock splits, stock dividends, combinations or reclassification of the Beta common stock) are reserved for issuance under the Stock Option Plan. On September 11, 2000, stock options exercisable for a total of 97,500 shares of Beta common stock were granted to a total of 6 employees as incentive stock options. This had been reported in the 1999 10-K as being issued in 1999, however, the Amended 1999 Incentive and Nonstatutory Stock Option Plan was not approved by a majority of the shareholders until September 11, 2000. Of this amount, stock options for a total of 95,000 shares of Beta common stock were granted to officers and directors who are employees. The average exercise price of such stock options is $6.00 per share, which represents an amount in excess of 110% of the fair market value of the average of the last reported highest bid and lowest asked prices quoted on the Nasdaq Small Cap Market on August 27, 1999, which was the date such stock options were originally approved to be granted. Also on September 11, 2000, stock options exercisable for a total of 51,000 shares of Beta common stock were granted to a total of 6 employees as incentive stock options resulting from the conclusion of the merger. None of these 6 employees were officers or directors. On December 8, 2000, stock options exercisable for a total of 135,000 shares of Beta common stock were granted to a total of 9 employees as incentive stock options. Of this amount, stock options for a total of 90,000 shares of Beta common stock were granted to officers and directors who are employees. The average exercise price of such stock options is $7.70 per share, which represents an amount in excess of 110% of the fair market value of the average of the last reported highest bid and lowest asked prices quoted on the Nasdaq National Market System on December 8, 2000.
The Stock Option Plan requires that the exercise price of the stock options granted under such plan shall not be less than (but may be higher than) 100% of the fair market value per share as determined on the date of grant. However, if an employee who is granted a Stock Option owns, at the time of grant, stock representing more than 10% of the voting power of all classes of Beta stock, the exercise price for options which are incentive stock options may not be less than 110% of the fair market value per share on the date of grant.
So long as our stock is reported on the National Association of Securities Dealers, Inc. Automated System, the fair market value per share on the date of grant of a stock option under the Stock Option Plan shall be the average of the last reported highest bid and the lowest asked prices quoted on the Nasdaq National Market System on such date.
The Stock Option Plan will continue in effect for 10 years from August 20, 1999 (i.e., the date first adopted by our board of directors), unless sooner terminated by our board of directors. Unless otherwise provided by our 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 Beta.
The options granted under the Stock Option Plan are for a period of not more than 10 years after the date of grant. However, in the case of an optionee who owns, at the time of grant, stock representing more than 10% of the combined voting power of all classes of Beta stock, the term of the options shall not be for more than five (5) years.
Upon the termination of an optionee as our employee, he/she must exercise his/her option within the period of time not exceeding three (3) months (as set forth in such stock option) after he/she ceases to be our employee. If an optionee becomes disabled and due to such disability ceases to be our employee, he/she must exercise his/her option within the period of time not exceeding 12 months (as set forth in such stock option). Upon the death of an optionee whose employment by us was not terminated prior to such event, the optionee's estate or person acquiring the right to exercise such option by bequest or inheritance may exercise such option at any time within 12 months following the date of such optionee's death but only to the extent that the optionee could have exercised such option (under its terms) if his/her employment had continued uninterrupted for such 12-month period.
The options granted under the Stock Option Plan may only be exercised by the optionee during his/her lifetime and are not transferable except by will or by the laws of descent and distribution. The shares of Beta common stock transferred to an optionee as a result of the exercise of a stock option are "restricted securities" under Rule 144 as promulgated under the 1933 Act and may only be resold or transferred in compliance with such rule and the registration requirements or an exemption from such requirements under the 1933 Act.
Retirement Plan We maintain a Savings Incentive Match Plan for Employees (SIMPLE IRA Plan) for eligible employees. Currently, all Beta employees are eligible to participate.
We presently make matching contributions to employee accounts in an amount equal to the elective contribution made by each employee, not to exceed, however, 3% of each employee's salary during any calendar year. All contributions to employees' accounts are immediately 100% vested and become the property of each employee at the time of contribution, including employer contributions and income-deferral contributions. During 2000, we contributed an aggregate of $15,456 to the accounts of 9 employee participants. Of this amount, $4,500 was allocated to Mr. Antry's account.
Directors' Compensation Beta's Bylaws state that non-employee Directors of Beta shall not receive any stated salary for their services, but, by resolution of the Board of Directors, a fixed sum and expense of attendance, if any, may be allowed for attendance at each regular and special meeting of the Board of Directors. (All Beta directors receive actual expense reimbursements, and Beta currently pays $1,000 in fees per outside director per meeting up to a maximum of $2,000 in fees per outside director for combined meetings.) Beta maintains directors and officers liability insurance.
Employment Contracts We have executed an employment contract dated June 23, 1997 with our President and Chairman of the Board, Mr. Steve Antry. 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 Beta without cause upon the payment to Mr. Antry of the following:
(a) Options to acquire the common stock of Beta 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 Beta to Mr. Antry shall immediately vest and Beta shall not have the right to terminate or otherwise cancel any securities issued by Beta to Mr. Antry.
During the period from inception, June 6, 1997 through December 31, 1997, and for the years ended December 31, 1998 and 1999, R. Thomas Fetters, a director of Beta was paid $20,000, $60,000 and $75,000, respectively, pursuant to a consulting contract for exploration related services. Beta had a consulting agreement with Mr. Fetters which provides that he will provide part time geologic services to Beta for $5,000 per month. The agreement provided that Mr. Fetters serve as a director during the term of the agreement. It further provides that if Mr. Fetters is offered a full time position with Beta, his compensation will be increased to a salary of $125,000 per year. The agreement was terminated by mutual agreement effective January 1, 2000. Mr. Fetters is now a full time employee of Beta at an annual salary of $92,500 for 2000 increasing to $125,000 in 2001.
On June 23, 1997, we entered into an employment agreement with Steve Fischer to serve at Vice President of Capital Markets at an annual salary of $60,000. Under separate agreement, Mr. Fischer subscribed to 350,000 shares of Founders Shares at price of $0.05 per share. The subscription agreement provides that the shares shall vest over a three-year period.
On January 27, 1998, Beta issued 100,000 common stock purchase warrants exercisable at a price of $3.75 per share to J. Chris Steinhauser, the Chief Financial Officer of Beta. Mr. Steinhauser terminated his employment with us effective June 6, 2000. As part of his severance package his remaining unvested 25,000 warrants were allowed to vest on what would have been his next anniversary date or January 27, 2001.
Report of The Compensation Committee The information required pursuant to Item 402 (k) of Regulation S-K is incorporated by reference into Beta's Definitive Annual Proxy Statement which will be filed with the SEC within 120 days of December 31, 2000.
Performance Graph The information required pursuant to Item 402 (l) of Regulation S-K is incorporated by reference into Beta's Definitive Annual Proxy Statement which will be filed with the SEC within 120 days of December 31, 2000.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The following table will inform you, as of December 31, 2000, about the beneficial ownership of shares of Beta's common stock held by each person who beneficially owns more than 5% of the outstanding shares of the common stock, each person who is a director or officer of Beta and all persons as a group who are officers and directors of Beta, and as to the percentage of outstanding shares held.
Shares Issuable Upon the Exercise Approximate Percent Shares Beneficially of Stock Warrants of Class As of Name of Beneficial Owner Owned (1) and Options 12/31/00 --------------------------------------- ----------------------- --------------------- ----------------------
Mr. Steve Antry 1,500,000 90,000 12.79% Mrs. Lisa Antry, Jointly(2)
Mr. R. Thomas Fetters(3) 350,000 40,000 3.15%
Mr. Joe C. Richardson Jr. 400,000 - 3.24%
Mr. Stephen L. Fischer(4) 350,000 65,000 3.35%
Mr. John P. Tatum(5) 18,500 71,000 0.72%
Mr. Rolf Hufnagel (6) 1,168,000 - 9.46%
Mr. Joseph L. Burnett (7) - 100,000 0.80%
Mr. Robert C. Stone, Jr. (8) - 50,000 0.40%
----------------------- --------------------- ---------------------- All officers, key persons and directors as a group (8 persons) 3,786,500(12) 416,000 33.91% ======================= ===================== ======================
(1) Unless otherwise indicated, all shares of common stock are held directly with sole voting and investment powers. Securities not outstanding, but included in the beneficial ownership of each such person are deemed to be outstanding for the purpose of computing the percentage of outstanding securities of the class owned by such person, but are not deemed to be outstanding for the purpose of computing percentage of the class owned by any other person.
(2) Mr. Steve Antry and Mrs. Lisa Antry, husband and wife, own 1,500,000 shares as community property. This also includes 25,000 shares of common stock underlying stock warrants which are exercisable at $5.00 per share and expire on March 12, 2003, 40,000 shares of common stock underlying stock options which are exercisable at $6.00 per share and expire on December 31, 2004, and 25,000 shares of common stock underlying stock options which are exercisable at $7.70 per share and expire on December 8, 2005. Mr. Antry has been our President and Chairman of the Board of Directors since June 1997. Ms. Antry has been our Treasurer since June 1997 and previously also served as Secretary.
(3) This includes 25,000 shares of common stock underlying stock options that are exercisable at $6.00 per share and expire on December 31, 2004 and 15,000 shares of common stock underlying stock options that are exercisable at $7.70 per share and expire on December 8, 2005. Mr. Fetters has been our Managing Director of Exploration and a Director since June 1997. During the period from our inception, June 6, 1997, through December 31, 997, Mr. Fetters was paid $20,000 under a consulting contract for management and geologic evaluation. Mr. Fetters received $60,000 and $77,500 in consulting fees during the years ended December 31, 1998 and 1999, respectively.
(4) This includes 25,000 shares of common stock underlying presently exercisable stock warrants. The warrants are exercisable at $5.00 per share and expire on March 12, 2003. In addition, this includes 15,000 shares of common stock underlying stock options that are exercisable at $6.00 per share and expire on December 31, 2004, and 15,000 shares of common stock underlying stock options that are exercisable at $7.70 per share and expire on December 8, 2005. Mr. Fischer has been our Vice President of Capital Markets since June 1997.
(5) This includes 46,000 shares underlying common stock warrants which are exercisable at a price of $5.00 per share and which expire April 1, 2004 and 25,000 shares underlying common stock warrants which are exercisable at a price of $10.25 per share and which expire March 16, 2005. Mr. Tatum has been a Director since March 1999. Mr. Tatum is a partner with Dyad Petroleum Company in Midland, Texas. Beta purchased a 20% interest in a property owned by an affiliate of Dyad at a cost of $100,000 in January 1999, prior to the time Mr. Tatum joined Beta as a Director.
(6) Mr. Hufnagel joined Beta as a director on June 6, 2000 and resigned his directorship on October 16, 2000. He is the former Red River President and received his shares in connection with the Merger that was consummated on August 30, 2000.
(7) Mr. Burnett became the Chief Financial Officer of Beta on June 6, 2000 after J. Chris Steinhauser resigned. On May 31, 2000, Beta issued 100,000 common stock purchase warrants exercisable at a price of $8.38 per share, of which 70,000 are currently exercisable by Mr. Burnett and shall expire on May 31, 2005. Mr. Burnett also received 30,000 shares of common stock underlying stock options that are exercisable at $7.70 per share and expire on December 8, 2005.
(8) Mr. Stone joined Beta as a director on September 19, 2000. This includes 50,000 shares underlying common stock warrants which are exercisable at a price of $10.00 per share and which expire October 1, 2005.
Item 13.
Item 13. Certain Relationships and Related Transactions
During the period from inception, June 6, 1997, through December 31, 1997, a director of Beta, Mr. R.T. Fetters, was paid $20,000 per a consulting contract for management and geologic evaluation services. Mr. Fetters received $60,000 and $75,000, respectively, in consulting fees during the years ended December 31, 1998 and 1999. In addition, on June 23, 1997, the director subscribed to 350,000 founder shares of Beta's common stock at a price of $0.05 per share. Mr. Fetters became an employee of the Company in January 2000.
A former director of Beta, Mr. Larry Horwitz, subscribed to 50,000 founder shares at a price of $0.05 per share. In addition, a legal firm with whom the former director was a shareholder, subscribed to 20,000 founder shares at a price of $0.05 per share. The legal firm also received a warrant to purchase 20,000 shares of Beta's common stock at a price of $6.00 per share. The warrants shall expire on September 1, 2004 if unexercised. The legal firm has represented Beta as general counsel.
On March 1, 2000, another director of Beta, Mr. Joe C. Richardson, Jr., subscribed to 400,000 founder shares at price of $0.05 per share. We have also entered into an Exploration and Development Area of Mutual Interest Agreement in Fremont County, Wyoming with Mr. Richardson. We have agreed to purchase from Mr. Richardson certain geology and lease acreage approximating 1,627 acres in a prospect located therein for $154,800. We will acquire a 75% working interest in such prospect. Mr. Richardson will back in to a 25% working interest after our investment from the first two wells drilled if the prospect pays out. All future exploration and development costs will be shared accordingly with our being responsible for 75% and Mr. Richardson being responsible for 25% of such costs.
Another director of Beta, Mr. John P. Tatum, is a partner with Dyad Petroleum Company in Midland, Texas. We purchased a 20% interest in foreign property owned by an affiliate of Dyad at a cost of $100,000 in January 1999, prior to the time Mr. Tatum joined Beta as a director.
There are no outstanding loans to officers, directors and related persons. Our present policy does not permit loans to officers, directors and related persons.
All future transactions with affiliates of Beta are to be on terms no less favorable than could be approved by a majority of the directors including the majority of disinterested directors. Management of Beta believes that all past related party transactions were as favorable to the Company or its affiliates as those generally available from unaffiliated third parties. At the time these transactions were entered into, Beta lacked sufficient disinterested independent directors to ratify the transactions. However, Beta has now obtained ratification from its independent, disinterested directors.
Other Information - Submission of Matters to a Vote of Security Holders Our annual meeting of shareholders was held at the Marriott Newport Beach Hotel and Tennis Club (at Fashion Island), 900 Newport Center Drive, Newport Beach, California on Saturday, June 24, 2000, at 2:00 P.M. Pacific Daylight Time. The matters submitted to a vote of our shareholders as well as the results of the votes cast are as follows:
Matters voted upon by holders of common Stock:
Proposal No. 1: Election of directors. A summary of the votes cast is as follows:
% of out- Number % of Number % of Number For standing shares Against out-standing Abstain out-standing shares shares ------------- --------------- ------- ------------ --------- ------------ Steve Antry 8,468,857 87% 400 0.004% 3,610 0.04% R. Thomas Fetters 8,468,857 87% 400 0.004% 3,610 0.04% Joe C. Richardson, Jr. 8,468,857 87% 400 0.004% 3,610 0.04% Lawrence W. Horwitz 8,468,857 87% 400 0.004% 3,610 0.04% John P. Tatum 8,468,857 87% 400 0.004% 3,610 0.04% Rolf N. Hufnagel 8,468,857 87% 400 0.004% 3,610 0.04%
As a result of the voting, Steve Antry, R. Thomas Fetters, Joe C. Richardson, Jr., Lawrence W. Horwitz, John P. Tatum and Rolf N. Hufnagel were elected as our directors to serve in that capacity until the annual meeting of shareholders in 2001.
Proposal No. 2: Amendment to Beta's Articles of Incorporation. A summary of the votes cast is as follows:
% of out- % of out- Number % of out- Number For standing shares Number Against standing shares Abstain standing shares ---------- --------------- -------------- --------------- --------- --------------- 6,250,634 64% 319,370 5.11% 40,607 0.65%
Prior to the approval of the Amendment, our Articles of Incorporation authorized 50,000,000 shares of $0.001 par value common stock. The Amendment did not change the number of authorized shares of common stock. The Amendment authorized 5,000,000 shares of $0.001 par value preferred stock.
Proposal No. 3: Ratification of Appointment of Independent Auditors. A summary of the votes cast is as follows:
% of out- % of out- Number % of out- Number For standing shares Number Against standing shares Abstain standing shares ---------- --------------- -------------- --------------- --------- --------------- 8,431,817 87% 29,165 .30% 11,885 .14%
We engaged Hein + Associates LLP as independent auditors to perform the audit of our financial statements for fiscal year 2000.
Subsequent Events On March 20, 2001, we opened a Preferred Private Placement Offering with a minimum of $1,500,000 and a maximum of $5,000,000 offered as units, each unit consisting of one share of Series A 8% Convertible Preferred Stock and one-half warrant to purchase one share of common stock. The Private Placement Offering is scheduled to close on April 30, 2001, but we may terminate earlier or extend to no later than June 30, 2001. We have the option to expand the proceeds from the offering to a maximum of $10,000,000. We also have the option of extending the escrow for up to 60 days. The proceeds from the offering will be used for corporate capital requirements and other corporate purposes.
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:
Certificate of Amendment to Articles of Incoroporation dated August 28, 2000. Mushroom Project Participation Agreement, Austin and Waller Counties, Texas, dated June 14, 2000. Starboard Area Letter Agreement, Terrebone Parish, Louisiana dated June 16, 2000. First Amended and Restated Revolving Credit Agreement dated March 30, 1999. First Amendment to First Amended and Restated Revolving Credit Agreement dated February 1, 2000. Second Amendment to First Amended and Restated Revolving Credit Agreement dated March 19, 2000. Third Amendment to First Amended and Restated Revolving Credit Agreement dated March 19, 2001. Form of Placement Agent Agreement for Preferred Placement dated March 15, 2001. List of Subsidiaries Consent of Hein + Associates, LLP. Consent of Ryder Scott and Associates.
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, 2000.
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION 3.1 Original Articles of Incorporation of Registrant incorporated by reference to Exhibit 3.1 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 3.2 Amended and Restated Bylaws of the Registrant, Dated October 29, 1998, incorporated by reference to Exhibit 3.2 of Betas 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. 10.1 Formosa Grande Prospect Agreement, Dated August 1, 1997, incorporated by reference to Exhibit 10.1 of Betas 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 Betas 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 Betas 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 Betas 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 Betas 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 Betas 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 Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.8 Agreement With Jim Frimodig (Norcal), Dated October 27, 1997, incorporated by reference to Exhibit 10.8 of Betas 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 Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.10 Steve Fischer, Employment Agreement, Dated June 23, 1997, incorporated by reference to Exhibit 10.10 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.11 J. Chris Steinhauser Warrant Agreement, Dated January 27, 1998, incorporated by reference to Exhibit 10.11 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.12 R.T. Fetters Consulting Agreement, Dated June 23, 1997, incorporated by reference to Exhibit 10.12 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.13 Office Lease, Dated October 1997, incorporated by reference to Exhibit 10.13 of Betas 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). 10.14 BWC Prospect Agreement, Dated April 1, 1998, incorporated by reference to Exhibit 10.14 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.15 Dahlia Financial Limited Consulting Agreement, Dated September 5, 1997, incorporated by reference to Exhibit 10.15 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.16 St. Cloud Investments, Ltd., Dated March 12, 1998, incorporated by reference to Exhibit 10.16 of Beta S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.17 Beta Oil "&" Gas / Beta Capital Group Reciprocal Agreement, incorporated by reference to Exhibit 10.17 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.18 Cobra Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.18 of Betas 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). 10.19 Redfish Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.19 of Betas 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 Betas 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 Betas 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 Betas 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) 10.23 Note and Common Stock Purchase Agreement Dated March 19, 1999, incorporated by reference to Exhibit 10.23 of Betas Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt) 10.24 Northeast Hitchcock Agreement Dated July 30, 1999, incorporated by reference to Exhibit 10.24 of Beta Form 10-K/A for the year 1999 filed March 30, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-00-000007.txt) 10.25 Sarah White Agreement Dated July 30, 1999, incorporated by reference to Exhibit 10.25 of Betas 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) Agreement and Plan of Merger by and between Red River Energy, Inc. and Beta Oil "&" Gas, Inc., 10.26 incorporated by reference to Annex A of Betas 14A Definitive Proxy Statement dated August 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000042-0001.htm). 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 Betas Third Quarter Form 10-Q filed November 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000052.txt). 10.28 Purchase Agreement dated September 19, 2000 between Red River Energy, L.L.C. and Duke Energy Financial Services, L.L.C., incorporated by reference to Exhibit 10.28 of Betas Third Quarter Form 10-Q filed November 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000052.txt). 10.29 Mushroom Project Participation Agreement, Austin and Waller Counties, Texas, dated June 14, 2000. 10.30 Starboard Area Letter Agreement, Terrebone Parish, Louisiana dated June 16, 2000. 10.31 First Amended and Restated Revolving Credit Agreement Dated March 30, 1999. 10.32 First Amendment to First Amended and Restated Revolving Credit Agreement dated February 1, 2000. 10.33 Second Amendment to First Amended and Restated Revolving Credit Agreement dated June 15, 2000. 10.34 Third Amendment to First Amended and Restated Revolving Credit Agreement dated March 19, 2001. 10.35 Form of Placement Agent Agreement for Preferred Placement dated March 15, 2001. 21 List of Subsidiaries 23.2 Consent of Hein + Associates, LLP. 23.3 Consent of Ryder Scott and Associates. 99 The Amended 1999 Incentive and Nonstatutory Stock Option Plan, incorporated by reference to Exhibit 99 of Betas 14A Definitive Proxy Statement dated 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, 2000, 1999 and 1998
Page
Independent Auditor's Report.........................................F-2
Consolidated Balance Sheets - December 31, 2000 and 1999.............F-3
Consolidated Statements of Operations - For the Years Ended December 31, 2000, 1999 and 1998..............................F-4
Consolidated Statement of Stockholders' Equity - For the Years Ended December 31, 2000, 1999 and 1998................................F-5
Consolidated Statements of Cash Flows - For the Years Ended December 31, 2000, 1999 and 1998..............................F-6
Notes to Consolidated Financial Statements...........................F-8
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, 2000 and 1999, and the related consolidated statements of operations, stockholders' equity, and cash flows for the three years in the period ended December 31, 2000. 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 generally accepted auditing standards. 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, 2000 and 1999 and the results of their operations and their cash flows for the three years in the period ended December 31, 2000 in conformity with generally accepted accounting principles.
/s/HEIN + ASSOCIATES LLP
HEIN + ASSOCIATES LLP Certified Public Accountants
Orange, California February 19, 2000, except for Note 4 and 12 which are as of March 20, 2001
BETA OIL "&" GAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS See accompanying notes to consolidated financial statements.
DECEMBER 31, 2000 DECEMBER 31, 1999 ------------------- ------------------ ------------------- ------------------ CURRENT ASSETS: Cash $ 1,536,186 $ 1,448,655 Accounts receivable Oil and gas sales 2,766,405 745,493 Other 95,439 1,178 Prepaid expenses 200,615 104,241 ---------------- ---------------- Total current assets 4,598,645 2,299,567
OIL AND GAS PROPERTIES, at cost (full cost method) Evaluated properties 43,110,463 9,810,198 Unevaluated properties 13,450,347 12,091,627 Less - accumulated amortization of full cost pool (6,354,905) (3,797,227) ---------------- ---------------- Net oil "&" gas properties 50,205,905 18,104,598
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost Gas gathering system 1,454,212 - Support equipment 1,505,496 - Other 114,672 38,303 Less - accumulated depreciation (158,918) (26,072) ----------------- ----------------- Net other operating property and equipment 2,915,462 12,231
OTHER ASSETS 746,140 465,079 ---------------- ----------------
TOTAL ASSETS $ 58,466,152 $ 20,881,475 ================ ================
CURRENT LIABILITIES: Current portion of long-term debt $ 89,209 $ 28,224 Accounts payable, trade 629,696 225,174 Income taxes payable 198,650 - Other accrued liabilities 147,853 11,901 ---------------- ---------------- Total current liabilities 1,065,408 265,299
LONG-TERM DEBT, less current portion 13,814,034 27,939 DEFERRED INCOME TAXES 3,526,304 - COMMITMENTS AND CONTINGENCIES (Note 4, 6, and 9) - -
STOCKHOLDERS' EQUITY Preferred stock, $.001 par value, 5,000,000 shares authorized; none issued or outstanding - - Common stock, $.001 par value; 50,000,000 shares authorized; 12,340,951 and 9,400,124 shares issued and outstanding at December 31, 2000 and 1999, respectively 12,341 9,400 Additional paid-in capital 46,592,976 28,549,313 Accumulated deficit (6,544,911) (7,970,476) ----------------- ----------------- Total stockholders' equity 40,060,406 20,588,237 ---------------- ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 58,466,152 $ 20,881,475 ================ ================
BETA OIL "&" GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ------------------- ------------------ ------------------
REVENUES: Oil and gas sales $ 8,037,234 $ 1,199,480 $ - Field services 320,633 - - ---------------- ---------------- ----------------- Total revenue 8,357,867 $ 1,199,480 - ---------------- ---------------- -----------------
COSTS AND EXPENSES: Lease operating expense 1,368,788 81,538 - Field services 147,325 General and administrative 2,141,005 1,418,240 746,769 Impairment expense - 1,224,962 1,670,691 Depreciation and amortization expense 2,693,439 914,233 11,883 ---------------- ---------------- ---------------- Total costs and expenses 6,350,557 3,638,973 2,429,343 ---------------- ---------------- ----------------
INCOME (LOSS) FROM OPERATIONS 2,007,310 (2,439,493) (2,429,343) ---------------- ----------------- ----------------
OTHER INCOME (EXPENSE): Interest expense (393,008) (2,966,651) - Interest income 105,563 21,741 44,843 ---------------- ---------------- ---------------- Total other income (expense) (287,445) (2,944,910) 44,843 ----------------- ----------------- ----------------
INCOME (LOSS) BEFORE TAX PROVISION 1,719,865 (5,384,403) (2,384,500)
PROVISION FOR INCOME TAXES (294,300) - - ----------------- ---------------- -----------------
NET INCOME (LOSS) $ 1,425,565 $ (5,384,403) $ (2,384,500) =============== ================= ================
BASIC NET INCOME (LOSS) PER COMMON SHARE $ 0.13 $ (0.66) $ (0.37) =============== =============== ===============
DILUTED NET INCOME (LOSS) PER COMMON SHARE $ 0.13 $ (0.66) $ (0.37) =============== =============== ===============
BETA OIL "&" GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY FOR THE YEARS ENDED DECEMBER 31, 2000, 1999, AND 1998.
See accompanying notes to consolidated financial statements.
Additional Total Common Stock Paid-In Accumulated Stockholders' Shares Amount Capital Deficit Equity ------------------- ------------------- ------------------- ------------------- --------------------
BALANCES, January 1, 1998 5,565,648 $ 5,566 $ 9,246,217 $ (201,573) $ 9,050,210
Issuance of common stock, net of offering costs 1,458,844 1,458 6,547,174 - 6,548,632 Warrants issued for properties 5,000 5 24,995 - 25,000 Salary contributed to Beta - - 60,000 - 60,000 Net loss - - - (2,384,500) (2,384,500) ---------------- ---------------- ---------------- ---------------- ----------------
BALANCES, December 31, 1998 7,029,492 7,029 15,878,386 (2,586,073) 13,299,342
Issuance of shares for bridge note financing 459,000 459 2,647,641 - 2,648,100 Salary contributed to Beta - - 10,000 - 10,000 Warrants issued to consultants - - 126,890 - 126,890 Warrants issued for properties - - 102,135 - 102,135 Issuance of shares for warrant exercises 446,142 446 2,052,174 - 2,052,620 Issuance of shares in initial public offering, net 1,465,490 1,466 7,732,087 - 7,733,553 Net loss - - - (5,384,403) (5,384,403) ---------------- --------------- ---------------- ------------------ -----------------
BALANCES, December 31, 1999 9,400,124 9,400 28,549,313 (7,970,476) 20,588,237
Issuance of shares for warrant exercises 665,827 666 3,114,473 - 3,115,139 Issuance of shares for option exercises 15,000 15 89,985 - 90,000 Issuance of shares upon merger 2,250,000 2,250 14,352,750 - 14,355,000 Issuance of shares for purchase of note 10,000 10 86,240 - 86,250 Warrants issued for purchase of note - - 226,030 - 226,030 Warrants issued to consultants - - 128,338 - 128,338 Warrants issued for property - - 45,847 - 45,847 Net income - - - 1,425,565 1,425,565 ---------------- ---------------- ---------------- ---------------- ----------------
BALANCES, December 31, 2000 12,340,951 $ 12,341 $ 46,592,976 $ (6,544,911) $ 40,060,406 ================ ================ ================ ================= ================
BETA OIL "&" GAS, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
BETA OIL "&"GAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Continued
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ------------------- ------------------- -------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 1,425,565 $ (5,384,403) $ (2,384,500) Adjustments to reconcile net (loss) to net cash provided by (used in) operating activities: Depreciation and amortization 2,693,439 914,233 11,883 Gain on sale of equipment (2,915) - - Amortization of notes payable discount and debt issuance costs - 2,754,000 - Impairment expense - 1,224,962 1,670,691 Warrants issued to consultants 128,338 126,890 - Salary contributed to Beta - 10,000 60,000 Change in operating assets and liabilities: Accounts receivable (1,140,077) (736,993) (9,678) Prepaid expenses (45,109) (89,290) (12,352) Accounts payable, trade 535 (85,596) (496,703) Income taxes payable 198,650 - - Commissions payable - - (25,329) Accrued payroll - 3,072 (16,485) Other accrued expenses (29,345) 1 470 (13,200) ---------------- --------------- ---------------- Net cash provided by (used in) operating activities 3,229,081 (1,262,655) (1,215,673) ---------------- ----------------- -----------------
CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas property expenditures (6,666,327) (6,945,695) (8,928,201) Change in other assets (278,287) (299,051) (166,028) Gas gathering and equipment expenditures (39,261) - - Cash acquired in merger 895,097 - - Proceeds received from equipment sale 100,000 - - Acquisition of other (52,942) (1,947) (2,762) ---------------- ----------------- -----------------
Net cash used in investing activities (6,041,720) (7,246,693) (9,096,991) ----------------- ----------------- -----------------
BETA OIL "&" GAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS Continued
See accompanying notes to consolidated financial statements FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ------------------- ------------------- ------------------- CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from sale of common stock, net - 7,733,553 6,548,632 Proceeds from exercise of warrants and options 3,205,139 2,052,620 - Proceeds from premiums payable 51,409 71,527 - Repayment of premiums payable (27,737) (15,364) - Proceeds from bridge notes payable - 2,894,100 - Repayment of bridge notes - (3,000,000) - Proceeds from notes payable 295,376 - - Repayment of notes payable (624,017) - - Increase (decrease) in deferred offering costs - 23,524 (23,524) ---------------- ---------------- -----------------
Net cash provided by financing activities 2,900,170 9,759,960 6,525,108 ---------------- ---------------- ----------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 87,531 1,250,612 (3,787,556)
CASH AND CASH EQUIVALENTS, at beginning of period 1,448,655 198,043 3,985,599 ---------------- ---------------- ---------------- CASH AND CASH EQUIVALENTS, at end of period $ 1,536,186 $ 1,448,655 $ 198,043 ================ ================ ================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid for: Interest $ 393,009 $ 123,552 $ - ================ ================ ========= Income taxes $ 46,375 $ 5,475 $ - ================ ================ =========
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES Fair value of common stock and warrants issued for: Net assets acquired, net of cash, through acquisition of RRE $ 13,459,903 $ - $ - Oil and gas properties $ 45,847 $ 102,135 $ 25,000 Common stock and warrants issued in settlement of debt $ 312,280 $ - $ -
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. Based on 2000 operating income, 100% of the Company's operations are 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 and 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 differ from these estimates and the difference could be material.
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 (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 unproved properties, net of tax considerations.
Joint Ventures - All exploration and production activities are conducted jointly with others and, accordingly, the accounts reflect only the Company's proportionate interest in such activities.
Revenue Recognition - The Company recognizes oil and gas sales upon delivery to the purchaser. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of the natural gas volume produced. Should the Company's excess sales of natural gas exceed its share of estimated remaining recoverable reserves a liability is recorded and revenue is deferred.
Furniture, Fixtures and Equipment - Furniture, Fixtures 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. 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 taxes 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. In accordance with FASB Statement No. 105, Disclosure of Information about Financial Instruments with Off-Balance-Sheet Risk and Financial Instruments with Concentrations of Credit Risk, the credit risk amounts shown in cash and accounts receivable do not take into account the value of any collateral or security.
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.
In the table below are the purchasers that each accounted for 10% or more of the Company's revenue during the specified years. 2000 1999 ----------------- -----------------
IP Petroleum 31% 53% Duke Energy 19% - Cokinos Energy 13% 38% Allegro Investments 12% -
At December 31, 2000, the Company maintained cash balances with a commercial bank which were approximately $1,348,700 in excess of FDIC insurance limits.
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 it carries interest rates which approximates 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. In accordance with FASB Statement No. 123 Accounting for Stock-Based Compensation (FASB123), the Company will disclose the impact of adopting 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.
Hedging Activities - The Company uses derivative commodity instruments on a limited basis to manage commodity price risk associated with future natural gas and crude oil production, but does not use them for speculative purposes. The Company's commodity price hedging program utilizes swap contracts. To qualify as a hedge, these contracts must correlate to anticipated future production such that the Company's exposure to the effects of commodity price changes is reduced. The gains and losses related to these hedging transactions are recognized as adjustments to revenue recorded for the related production. Effective July 1, 2000, the Company has committed for one year to sell 985,500 Mmbtu of natural gas at a price of $3.085 per Mmbtu, representing approximately 30% of the Company's average daily gas production.
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 in to 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.
Impact of Recently Issued Standards - In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133 (FASB133), "Accounting for Derivative Instruments and Hedging Activities." The FASB has subsequently issued Statement No. 137 and Statement No. 138 which are amendments to FASB133. FASB133, as amended, requires that an entity recognize all derivatives as assets or liabilities in the statement of financial position and measure those instruments at fair value. FASB133, as amended, is effective for fiscal years beginning after June 15, 2000. FASB133, as amended, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. The Company adopted SFAS133, as amended, beginning January 1, 2001. Management does not believe the adoption of FASB133 will have a material impact on the Company's financial position or results of operation.
2. ACQUISITIONS AND 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. A portion of the purchase price has been allocated to assets acquired and liabilities assumed of RRE based on the fair market value, 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 an independent reserve report. This amount will be 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.
Unaudited pro forma operating results for the Company, assuming the acquisition of RRE occurred on January 1, 2000, are as follows:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 -------------------- -----------------
Revenue $ 11,940,452 $ 4,388,238 ================ ================
Net income (loss) $ 713,235 (5,018,232) ================ ================
Basic earnings per share $ .07 $ (0.48) ================ ==============
Diluted earnings per share $ .06 $ (0.48) ================ ==============
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:
United States Foreign Total ------------------- ------------------ ------------------ 2000 Capitalized costs: Evaluated properties $ 41,429,542 $ 1,680,921 $ 43,110,463 Unevaluated properties 13,326,778 123,569 13,450,347 ---------------- ---------------- ---------------- 54,756,320 1,804,490 56,560,810 Accumulated depreciation, depletion, amortization and impairment (4,673,635) (1,681,270) (6,354,905) ---------------- ---------------- ---------------- Net capitalized costs $ 50,082,685 $ 123,220 $ 50,205,905 ================ ================ ================ Cost incurred: Property acquisition (1) $ 30,658,876 $ - $ 30,658,876 Exploration 3,514,875 5,126 3,520,001 Development 480,109 - 480,109 ---------------- ---------------- ---------------- Total costs incurred $ 34,653,860 $ 5,126 $ 34,658,986 ================ ================ ================
1999 Capitalized costs: Evaluated properties $ 8,128,928 $ 1,681,270 $ 9,810,198 Unevaluated properties 11,973,532 118,095 12,091,627 ---------------- ---------------- ---------------- 20,102,460 1,799,365 21,901,825 Accumulated depreciation, depletion, amortization and impairment (2) (2,115,957) (1,681,270) (3,797,227) ---------------- ---------------- ---------------- Net capitalized costs $ 17,986,503 $ 118,095 $ 18,104,598 ================ ================ ================ Cost incurred: Property acquisition $ 1,810,332 $ 114,632 $ $ 1,924,964 Exploration 5,122,866 - 5,122,866 Development - - - ---------------- ---------------- ---------------- Total costs incurred $ 6,933,198 $ 114,632 $ 7,047,830 ================ ================ ================ --------------- ----------------
1998 Capitalized costs: Evaluated properties $ 1,763,082 $ 1,624,218 $ 3,387,300 Unevaluated properties 11,426,732 39,963 11,466,695 ---------------- ---------------- ---------------- 13,189,814 1,664,181 14,853,995 Accumulated depreciation, depletion, amortization and impairment (3) (46,473) (1,624,218) (1,670,691) ---------------- ---------------- ---------------- Net capitalized costs $ 13,143,341 $ 39,963 $ 13,183,304 ================ ================ ================ Cost incurred: Property acquisition $ 2,808,123 $ 323,463 $ 3,131,586 Exploration 4,510,897 1,310,718 5,821,615 Development - - - ---------------- ---------------- ---------------- Total costs incurred $ 7,319,020 $ 1,634,181 $ 8,953,201 ================ ================ ================
(1) Includes $24,845,227 related to the properties acquired in the Merger and $3,526,304 related basis from deferred taxes.
(2) At December 31, 1999, the total costs in evaluated properties exceeded their net realizable values and accordingly an impairment write-down of $1,224,962 was recorded.
(3) In 1998 the Company, through its wholly-owned subsidiary Beta Australia, L.L.C., participated in the drilling of two offshore test wells as per the terms of two petroleum licenses covering certain acreage in Australia. The wells were completed as dry holes and the associated acquisition and exploration costs totaling $1,624,218 were transferred to evaluated properties and charged to impairment expense.
Evaluated oil "&" gas properties
United States - During the year ended December 31, 2000, Beta participated in the drilling of 21 wells and the associated property acquisition and exploration costs associated with the wells were transferred to evaluated properties. Amortization expense was $2,557,678 with $7.98 per barrel for equivalent units of oil and gas produced. Natural gas is converted to equivalent units of oil on the basis of six MCF of gas to one equivalent barrel of oil.
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 with $11.13 per barrel for equivalent units of oil and gas produced. Natural gas is converted to equivalent units of oil on the basis of six MCF of gas to one equivalent barrel of oil.
During the year ended December 31, 1998 Beta participated in the drilling of 6 wells within the United States. The property acquisition and exploration costs associated with the wells were transferred to evaluated properties and were evaluated for impairment. It was determined that the capitalized costs associated with the drilling of these properties exceed their net realizable value by $46,473. Accordingly, an impairment write-down of $46,473 was recorded for the year ended December 31, 1998. Since all of the proved reserves associated with the wells were non-producing or behind pipe and no production had occurred as of December 31, 1998 with no depletion expense was recorded during the year.
Foreign - There was no activity outside of the United States for the year ended December 31, 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:
United States Foreign Total ------------------- ------------------- ----------------- Revenues $ 8,037,234 $ - $ 8,037,234 Production costs (1,368,788) - (1,368,788) Depreciation, depletion and amortization (2,557,678) - (2,557,678) ---------------- ---------------- ---------------- Results of operations for producing activities (excluding generative administrative, financing costs and income taxes) $ 4,110,768 $ - $ 4,110,768 ================ ================ ================
1999: Revenues $ 1,199,480 $ - $ 1,199,480 Production costs (81,538) - (81,538) Depreciation, depletion and amortization (901,573) - (901,573) Impairment expense (1,167,910) (57,052) (1,224,962) ---------------- ---------------- ---------------- Results of operations for producing activities (excluding generative administrative, financing costs and income taxes) $ (951,541) $ (57,052) $ (1,008,593) ================ ================ ================
1998: Revenues $ - $ - $ - Production costs - - - Depreciation, depletion and amortization - - - Impairment expense (46,473) (1,624,218) (1,670,691) ---------------- ---------------- ---------------- Results of operations for producing activities (excluding generative administrative, financing costs and income taxes) $ (46,473) $ (1,624,218) $ (1,670,691) ================ ================ ================
Unevaluated oil "&" gas properties
At December 31, 2000, 1999 and 1998, unevaluated properties consists of the following:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ------------------ ------------------- -------------------
Unproved $ 8,547,825 $ 7,056,414 $ 6,476,043 Exploration 4,902,522 5,035,213 4,990,652 ---------------- ---------------- ---------------- $ 13,450,347 $ 12,091,627 $ 11,466,695 ================ ================ ================
United States - As Beta'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, 2000 and 1999 represent property acquisition and exploration costs in connection with Beta's Louisiana and Texas prospects. The prospects and their related costs in unevaluated properties have been assessed individually and no impairment charges were considered necessary for the United States Properties for any of the periods presented. The current status of these prospects is that seismic has been acquired, processed 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 basis.
The unevaluated costs for Beta's remaining California prospects were 100% impaired and transferred to evaluated properties. Management anticipates that the planned activities for 2001 will enable the evaluation for approximately 50% of the costs as of December 31, 2001. Evaluation of the remaining 50% of the costs will occur in 2002.
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 2001.
3. OTHER OPERATING PROPERTY AND EQUIPMENT: --------------------------------------
As a result of the Merger, other operating property and equipment were acquired and included 40 miles of pipeline in Eastern Oklahoma and specific equipment and vehicles related to oil and gas activities. For the year ended December 31, 2000, the Company recorded depreciation expense of $56,544. The Company recorded an additional depreciation expense for other equipment, which includes furniture and fixtures, of $79,215, $12,660 and $11,883 for the years ended December 31, 2000, 1999, and 1998, respectively.
At December 31, 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 in not in excess of the net realizable value.
4. LONG-TERM DEBT: --------------
Long-term debt consisted of the following:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 ----------------- ------------------- Notes payable under financing agreements for insurance premiums, bearing interest at rates ranging from 8.50% to 9.75%, due in monthly installments totaling $5,709 including interest, with maturity dates beginning June 1, 2001 through December 31, 2001. $ 79,832 $ 56,163 Note payable under a revolving credit agreement, due October 1, 2001, bearing interest at a LIBOR based rate plus 1.8% (8.56% at December 31, 2000), accrued interest payable monthly, collateralized by substantially all oil and gas properties owned by one of the Company's subsidiaries. Additionally, the Company has guaranteed the debt. 13,784,650 -
Note payable, due in monthly installments of $1,230 including interest maturing on December 19, 2003, collateralized by equipment. 38,761 - ---------------- ---------------- $ 13,903,243 56,163
Less current portion 89,209 28,224 ---------------- ---------------- $ 13,814,034 $ 27,939 ================ ================
The $13,784,650 note at December 31, 2000 arises from a credit agreement with a commercial bank for the Company that provides for maximum outstanding borrowings aggregating $25 million and matured on October 1, 2001. Subsequent to December 31, 2000, the Company amended this credit agreement extending the maturity date to March 15, 2003 and increasing the aggregate amount of advances to be limited to a collateral borrowing base of $14,400,000, which will be re-determined semi-annually and collateralized by the Company's oil and gas properties. The Company will be required to maintain certain covenants of which the Company was in compliance at December 31, 2000.
Aggregate maturities required on long-term debt at December 31, 2000 are due in future years as follows:
2001 $ 89,209 2002 15,312 2003 13,798,722 2004 - 2005 - ---------------- Total $ 13,903,243 ================
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.
During the year ended December 31, 1999, the Company incurred interest expense of $2,966,651, substantially all of which related to the bridge notes. Interest expense related to the bridge notes for the 1999 period consists of the following:
Cash interest expense $ 120,555 Amortization of note discount and fair market value of 459,000 shares 2,754,000 Amortization of deferred loan costs 89,100 ----------------- Bridge note interest expense for the year ended December 31, 1999 $ 2,963,655 =================
The remaining $2,996 represents cash interest expense incurred in connection with financing insurance premiums.
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:
FOR THE YEARS ENDED DECEMBER 31, AMOUNT
2001 $ 150,715 2002 145,916 2003 130,186 2004 13,411 2005 3,587 ---------------- TOTAL $ 443,815 ================
Rent expense was $125,640, $33,000, and $31,000 for the years ended December 31, 2000, 1999 and 1998, 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. Should the litigation be resolved adversely to Beta, the net impact to Beta is estimated to be as of March 31, 2001 approximately $250,000 plus costs and litigation expense, if recoupment from various other working interest owners in the affected oil and gas properties is successful. If Beta is unable to recoup such damages, the net adverse impact to Beta is estimated to be approximately $550,000 plus costs and litigation expense.
7. STOCKHOLDERS' EQUITY: --------------------
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% a estimated time to expire of three years, at $226,030, 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 in Note 2.
Warrants -
During the year ended December 31, 1998, the Company completed a private placement offering of equity units at a subscription price of $20 per unit. Each unit consisted of four shares of the Company's common stock and one callable warrant to purchase on share of its common stock at a price of $7.50 per share for a period of five years from the date of issuance. Under this private placement, the Company issued 1,458,844 shares of common stock and 364,708 warrants exercisable at $7.50 per share. The offering generated net proceeds of $6,548,632. In connection with the offering, the Company issued 482,100 warrants with exercise prices ranging from $5.00 to $7.50 per share for services rendered.
Also, during the year ended December 31, 1998, the Company issued 5,000 shares of common stock and 1,250 warrants for properties for a total value of $25,000.
On January 27, 1998, the Company issued 100,000 warrants with an exercise price of $3.75 per share to an officer of the Company. The exercise price was equal to the market value of the common stock on the date of grant and vest over three years. At December 31, 1999, 75,000 of the warrants had fully vested. Upon the officers termination of employment in May 2000, the company accelerated the vesting of the remaining 25,000 warrants not vested and recognizing additional compensation of $128,338.
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 Company issued 225,000 and 51,000 warrants to employees and directors of the Company during the years ended December 31, 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. Of the 225,000 employee warrants, 150,000 vest over a three-year period and the remaining 75,000 vest immediately. The warrants issued vested immediately and expire in 2004 and 2005.
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 of $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%, a risk free interest rate ranging from 5.70% to 5.84%, and two-year period to expiration.
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% and 5.77% and an estimated time to expire of three years. The warrants vest immediately and begin to expire in 2006.
The following table summarizes the number of shares reserved for the exercise of common stock purchase warrants as of December 31, 2000:
AVERAGE EXERCISE NUMBER OF SHARES PRICE PER SHARE -------------------- -------------------
BALANCE, January 1, 1998 1,528,222 $ 4.47 Granted 969,441 6.45 Forfeited/Cancelled - - Exercised - - ---------------- ----------------
BALANCE, December 31, 1998 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 ================ ================
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, before the Company may call those warrants. At December 31, 2000, 440,679 warrants were callable with a weighted average exercise price of $7.30 per share. The remaining 1,516,692 warrants outstanding are non-callable warrants with a weighted average price of $6.22 per share. If not previously exercised, 474,986 warrants will expire in 2002, 823,263 warrants will expire in 2003, 319,122 warrants will expire in 2004 and 340,000 warrants will expire in 2005.
Stock Option Plan -
In August 2000, the Company adopted the 1999 Incentive and Nonstatutory Stock Option Plan (the 1999 plan) covering 700,000 shares which 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 whom 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 August 1999, the Company granted options to purchase 97,500 shares of common stock to employees under the 1999 plan which did not become effective until the shareholders had approved the 1999 stock option plan. The options were granted with an exercise prices 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 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.
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.
The following table sets forth activity for all options granted under the 1999 Plan:
NUMBER OF SHARES AVERAGE EXERCISE PRICE PER 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 ================ ===============
At December 31, 2000, options to purchase 228,000 shares were exercisable at prices ranging from $6.00 to $9.00 per share. The remaining 38,000 options outstanding become exercisable with an exercise prices of $9.00 per share through March 2004.
If not previously exercised the outstanding plan options will expire as follows:
AVERAGE EXERCISE NUMBER OF PRICE PER SHARE PERIOD ENDED DECEMBER 31, SHARES ----------------------------------------- -------------------- ---------------------
2009 80,000 $ 6.00 2010 186,000 8.06 ---------------- --------------- 266,000 $ 7.44 ================ ===============
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 and warrants issued to employees been determined based on the fair value at grant date for awards in 1999 and 2000 consistent with the provisions of FASB123, the Company's net loss and net loss per share would have been adjusted to the proforma amounts indicated below:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ------------------ ------------------- -----------------
Net income (loss) $ 900,618 $ (5,470,000) $ (2,473,000) ================ ================ ================ Basic and diluted net income (loss) per common share $ .08 $ (0.67) $ (0.39) ================ ================ ================
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, 2000, 1999 and 1998 was $3.18, $ 1.68 and $4.31 per share, respectively.
8. INCOME TAXES: ------------
Income tax expense (benefit) for the indicated periods is comprised of the following:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ---------------------- ------------------- ------------------- Current Federal $ 51,000 $ - $ - State 243,300 - - ---------------- ------------ ------------ $ 294,300 $ - $ - ================ ================== ============
Deferred Federal - - - State - - - ---------------- ---------------- ---------- $ - $ - $ - ================ ================ ==========
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:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 ---------------------- ------------------- ------------------- Amount of expected tax benefit (expense) $ (569,287) $ 1,829,677 $ 810,458 Non-deductible expenses (48,207) (13,846) (23,759) State taxes, net (143,748) (800) (800) Change in beginning balance of valuation allowance 175,473 (1,815,831) (786,699) Alternative minimum tax (51,000) - - Utilization of net operating loss carry-forwards 342,469 - - ---------------- ---------------- -------- $ (294,300) $ (800) $ (800) ================ ================ ================
The components of the net deferred tax asset and liability recognized are as follows:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 -------------------- -------------------
Long-term deferred tax assets (liabilities): Net operating loss carry-forwards $ 4,218,944 $ 3,989,087 Equipment 1,478,797 130 Oil and gas properties (9,224,045) (695,387) ---------------- ----------------- (3,526,304) 3,293,830 Valuation allowance - (3,293,830) ---------------- ----------------- Net long-term deferred tax asset (liability) $ (3,526,304) $ - ================ =========
At December 31, 2000, the Company has Federal net operating loss carry forward of approximately $11,624,000 which expire in the years 2013 through 2020. The Company has California net operating loss carry forwards for the year ended December 31, 2000 of $6,590,000 which expire in 2006.
Utilization of the tax net operating loss carry-forward may be limited in the event a 50% or more change in ownership occurs within a three-year period.
9. OTHER: -----
Related Party Transactions -
For the years ended December 31, 1999 and 1998, a director of the Company was paid $75,000 and $60,000, respectively, 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.
A former director of the Company subscribed to 50,000 founder shares at a price of $0.05 per share. The legal firm with whom the director was a shareholder, also subscribed to 20,000 founder shares at a price of $0.05 per share. The legal firm represented the Company as general counsel at that time. The legal firm also received 20,000 common stock purchase warrants presently exercisable at a price of $6.00 per share until expiration on September 1, 2004.
Another director of the Company subscribed to 400,000 founder shares at price of $0.05 per share. The Company has also entered into an Exploration and Development Area of Mutual Interest Agreement in Fremont County, Wyoming with the Director. The Company has agreed to purchase certain geology and lease acreage approximating 1,627 acres in a prospect located therein for $154,800 from said Director. The Company will acquire a 75% working interest in such prospect. The Director will back in to a 25% working interest after our investment from the first two wells drilled if the prospect pays out. All future exploration and development costs will be shared accordingly with the Company being responsible for 75% and the Director being responsible for 25% of such costs.
Another Director of the Company is a partner with Dyad Petroleum Company in Midland, Texas. The Company purchased a 20% interest in a property owned by an affiliate of Dyad at a cost of $100,000 in January 1999, prior to the time the Director joined the Company's Board.
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 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.
On June 23, 1997, the Company entered into an employment agreement with a shareholder. The agreement provided for a two-year term at an annual salary of $60,000 for services as "Vice President of Capital Markets". The agreement has subsequently expired. Under separate agreement, the Shareholder subscribed to 350,000 shares of Founders Shares at a price of $0.05 per share. The subscription agreement provides that the shares shall vest over a three-year period.
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 employees eligible compensation. The Company's contribution to the plan for the years ended December 31, 2000 and 1999 was $ 15,456 and $4,693, respectively.
10. OTHER ASSETS: ------------
Other assets of approximately $746,000 and $465,000 at December 31, 2000 and December 31, 1999, respectively, consisted primarily of unapplied well prepayments.
11. NET INCOME (LOSS) PER COMMON SHARE:
The following represents the calculation of net income (loss) per common share:
2000 1999 1998 ------------------ ------------------ ------------------ Basic Net income (loss) applicable to common shareholders $ 1,425,565 $ (5,384,403) $ (2,384,500) ================ ================= =================
Weighted average number of shares 10,616,692 8,160,000 6,366,923 ================ ================ ================
Basic earnings (loss) per share $ .13 $ (.66) $ (.37) ================= ================= =================
Diluted Net income (loss) applicable to common shareholders $ 1,425,565 $ (5,384,403) $ (2,384,500) ================ ================= =================
Weighted average number of shares 10,616,692 8,160,000 6,366,923 Common stock equivalent shares representing shares issuable upon exercise of stock options and warrants 664,721 - - ---------------- ---------------- ----------------- Weighted average number of shares used in calculation of diluted income (loss) per share 11,281,413 8,160,000 6,366,923 ================ ================ ================
Diluted earnings (loss) per share $ .13 $ (.66) $ (.37) ================= =================== ==================
12. SUBSEQUENT EVENTS:
On March 20, 2001, the Company opened a Preferred Private Placement Offering with a minimum of $1,500,000 and a maximum of $5,000,000 offered as units, each unit consisting of one share of Series A 8% Convertible Preferred Stock and one-half warrant to purchase one share of common stock. The Private Placement Offering is scheduled to close on April 30, 2001, but may be terminated earlier or extended to no later than June 30, 2001 by the Company. The Company has the option to expand the proceeds from the offering to a maximum of $10,000,000. It also has the option of extending the escrow for up to 60 days. The proceeds from the offering will be used for corporate capital requirements and other corporate purposes.
13. UNAUDITED SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION: -------------------------------------------------------
The following supplementary information is presented in compliance with United States Securities and Exchange Commission ("SEC") regulations and is not covered by the report of the Company's independent auditors.
The information required to be disclosed for the year ended 1998 and after in accordance with FASB Statement No. 69, "Disclosures About Oil and Gas Producing Activities," is discussed below and is further detailed in the following tables.
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 Company's reserves are substantially all proved developed. The reserve data is based on studies prepared by the Company's independent consulting petroleum engineers. Reserve estimates require substantial judgement 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, 2000, the Company's proved oil and gas reserve quantities 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, 2000, 1999 and 1998:
Changes in Quantities of Proved Petroleum and Natural Gas Reserves (unaudited)
PROVED RESERVES OIL (BBLS) GAS (MCF) ------------------- -------------------- Proved reserves, December 31, 1997 - - Extensions and discoveries 1,461 1,596,740 -------------- --------------
Proved reserves, December 31, 1998 1,461 1,596,740 Extensions and discoveries 13,932 4,228,627 Production (1,822) (475,065) Revisions of previous estimates (370) (1,180,302) ---------------- ---------------
Proved reserves, December 31, 1999 13,201 4,170,000 Extensions and discoveries 19,153 2,308,520 Purchase of minerals in place 735,484 14,981,000 Production (32,617) (1,726,416) Revision of previous estimates 78,749 (315,104) ---------------- ---------------- Proved reserves, December 31, 2000 813,970 19,418,000 =============== ==============
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 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, 2000, 1999 and 1998 based on the standardized measure prescribed in Statement of Financial Accounting Standard No. 69:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 -------------------- -------------------- -------------------
Future cash inflows $ 204,303,798 $ 9,141,659 $ 2,978,861 Future costs- Production (28,592,624) (905,242) (343,478) Development (1,123,359) (701,771) (81,621) -------------------- -------------------- ------------------- Future net cash inflows before income tax 174,587,815 7,534,646 2,553,762 Future income tax (49,221,755) - - -------------------- -------------------- ------------------- Future net cash flows 125,366,060 7,534,646 2,553,762 10% discount factor (53,907,406) (1,521,674) (837,154) -------------------- -------------------- -------------------
Future net cash flows $ 71,458,654 $ 6,012,972 $ 1,716,608 ==================== ==================== ===================
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, 2000, 1999 and 1998:
FOR THE YEARS ENDED DECEMBER 31, 2000 1999 1998 -------------------- -------------------- -------------------
Standardized measure, beginning of year $ 6,012,972 $ 1,716,608 $ - Sale of oil and gas produced, net of production costs (6,668,446) (1,117,942) - Purchase of minerals in place 77,595,310 - - Extensions and discoveries 15,200,178 6,374,495 1,716,608 Changes in income taxes, net (28,056,400) - - Changes in prices and costs 21,485,597 447,063 - Changes in development costs 78,373 (443,525) - Accretion of discount 601,297 171,661 - Revisions of estimates and other (14,790,227) (1,135,388) - -------------------- -------------------- -------------------
Standardized measure, end of year $ 71,458,654 $ 6,012,972 $ 1,716,608 ==================== ==================== ===================
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 30, 2001
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.
Signature Title Date
/s/ Steve Antry___ Chairman of the March 30, 2001 ------------------- Steve Antry Board of Directors and President
/s/ Joseph L. Burnett Chief Financial Officer, March 30, 2001 ------------------------ Joseph L. Burnett and Principal Accounting Officer
R.T. Fetters Director March 30, 2001 --------------------- R.T. Fetters
/s/ Joe C. Richardson, Jr. Director March 30, 2001 ------------------------------- Joe Richardson Jr.
/s/ John P. Tatum Director March 30, 2001 ------------------------- John P. Tatum
/s/ Robert C. Stone, Jr. Director March 30, 2001 ------------------------- Robert C. Stone, Jr.
INDEX TO EXHIBITS
EXHIBIT NUMBER DESCRIPTION 3.1 Original Articles of Incorporation of Registrant incorporated by reference to Exhibit 3.1 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 3.2 Amended and Restated Bylaws of the Registrant, Dated October 29, 1998, incorporated by reference to Exhibit 3.2 of Betas 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.
10.1 Formosa Grande Prospect Agreement, Dated August 1, 1997, incorporated by reference to Exhibit 10.1 of Betas 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 Betas 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 Betas 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 Betas 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 Betas 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 Betas 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 Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.8 Agreement With Jim Frimodig (Norcal), Dated October 27, 1997, incorporated by reference to Exhibit 10.8 of Beta 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-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.10 Steve Fischer, Employment Agreement, Dated June 23, 1997, incorporated by reference to Exhibit 10.10 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.11 J. Chris Steinhauser Warrant Agreement, Dated January 27, 1998, incorporated by reference to Exhibit 10.11 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.12 R.T. Fetters Consulting Agreement, Dated June 23, 1997, incorporated by reference to Exhibit 10.12 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.13 Office Lease, Dated October 1997, incorporated by reference to Exhibit 10.13 of Betas 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). 10.14 BWC Prospect Agreement, Dated April 1, 1998, incorporated by reference to Exhibit 10.14 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.15 Dahlia Financial Limited Consulting Agreement, Dated September 5, 1997, incorporated by reference to Exhibit 10.15 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.16 St. Cloud Investments, Ltd., Dated March 12, 1998, incorporated by reference to Exhibit 10.16 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.17 Beta Oil "&" Gas / Beta Capital Group Reciprocal Agreement, incorporated by reference to Exhibit 10.17 of Betas S-1 Registration Statement No. 333-68381 filed December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt). 10.18 Cobra Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.18 of Betas 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). 10.19 Redfish Prospect Agreement Dated January 6, 1999, incorporated by reference to Exhibit 10.19 of Betas 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 Betas 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 Betas 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 Betas 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) 10.23 Note and Common Stock Purchase Agreement Dated March 19, 1999, incorporated by reference to Exhibit 10.23 of Betas Amendment No. 2 to S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt) 10.24 Northeast Hitchcock Agreement Dated July 30, 1999, incorporated by reference to Exhibit 10.24 of Betas Form 10-K/A for the year 1999 filed March 30, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/0001059324-00-000007.txt) 10.25 Sarah White Agreement Dated July 30, 1999, incorporated by reference to Exhibit 10.25 of Betas 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) Agreement and Plan of Merger by and between Red River Energy, Inc. and Beta Oil "&" Gas, Inc., 10.26 incorporated by reference to Annex A of Betas 14A Definitive Proxy Statement dated August 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000042-0001.htm). 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 Betas Third Quarter Form 10-Q filed November 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000052.txt). 10.28 Purchase Agreement dated September 19, 2000 between Red River Energy, L.L.C. and Duke Energy Financial Services, L.L.C., incorporated by reference to Exhibit 10.28 of Betas Third Quarter Form 10-Q filed November 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000052.txt). 10.29 Mushroom Project Participation Agreement, Austin and Waller Counties, Texas, dated June 14, 2000. 10.30 Starboard Area Letter Agreement, Terrebone Parish, Louisiana dated June 16, 2000. 10.31 First Amended and Restated Revolving Credit Agreement Dated March 30, 1999. 10.32 First Amendment to First Amended and Restated Revolving Credit Agreement dated February 1, 2000. 10.33 Second Amendment to First Amended and Restated Revolving Credit Agreement dated June 15, 2000. 10.34 Third Amendment to First Amended and Restated Revolving Credit Agreement dated March 19, 2001. 10.35 Form of Placement Agent Agreement for Preferred Placement dated March 15, 2001. 21 List of Subsidiaries 23.2 Consent of Hein + Associates, LLP. 23.3 Consent of Ryder Scott and Associates. 99 The Amended 1999 Incentive and Nonstatutory Stock Option Plan, incorporated by reference to Exhibit 99 of Betas 14A Definitive Proxy Statement dated August 14, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/000105932400000042/0001059324-00-000042-0001.htm).