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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
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WASHINGTON, D.C. 20549
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FORM 10-K
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Year Ended December 31, 2001
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ___________ to __________
Commission File Number: 000-25717
[GRAPHIC OMITTED][GRAPHIC OMITTED]
BETA OIL & GAS, INC.
(Exact name of registrant as specified in its charter)
Nevada 86-0876964
(State of Incorporation) (I.R.S. Employer Identification No.)
6120 S. Yale, Suite 813, Tulsa, OK 74136
(Address of principal executive offices) (Zip Code)
(918) 495-1011
(Registrant's telephone number, including area code)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ____
Check if disclosure of delinquent filers in response to Item 405 of Regulation
S-K is not contained within this form, and no disclosure will be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
As of March 15, 2002, 12,398,572 shares of the registrant's common stock were
outstanding. The aggregate market value of such common stock held by
non-affiliates was approximately $53,065,888 based on the reported closing sales
price of $4.28 on the Nasdaq Market on that date.
Certain sections of the registrant's annual proxy statement for the 2002 annual
meeting of stockholders on or about June 1, 2002 is incorporated by reference
into Part III.
Exhibit table is on page 39.
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TABLE OF CONTENTS
PART I - FINANCIAL INFORMATION Page
Glossary of Terms 2
Disclosure Regarding Forward-Looking Statements 5
Risk Factors 6
ITEM 1. Business Of Beta 7
ITEM 2. Properties Of Beta 19
ITEM 3. Legal Proceedings 20
ITEM 4. Submission Of Matters To A Vote Of Security Holders 20
PART II
ITEM 5. Market For Registrant's Common Equity And Related
Stockholder Matters 21
ITEM 6. Selected Financial Data 22
ITEM 7. Management's Discussion And Analysis 24
ITEM 7A. Quantitative And Qualitative Disclosure About Market Risk 34
ITEM 8. Financial Statements And Supplementary Data 34
ITEM 9. Changes In And Disagreements With Accountants On Accounting
And Financial Disclosure 34
PART III
ITEM 10. Directors, Executive Officers, Promoters And Control Persons;
Compliance With Section 16(A) Of The Exchange Act 35
ITEM 11. Executive Compensation . 35
ITEM 12. Security Ownership Of Certain Beneficial Owners And Management 35
ITEM 13. Certain Relationships And Related Transactions 35
PART IV
ITEM 14. Exhibits, Financial Statement Schedules And Reports On Form 8-K 36
Signatures 38
Exhibits 39
1
GLOSSARY OF TERMS
We are in the business of exploring for and producing oil and natural
gas. Oil and gas exploration is a specialized industry. Many of the terms used
to describe our business are unique to the oil and gas industry. We present the
following glossary to clarify certain of these terms you may encounter while
reading this Form 10-K.
"Acquisition costs of properties" means the costs incurred to obtain rights
to production of oil and gas. These costs include the costs of acquiring oil and
gas leases and other interests. These costs include lease costs, finder's fees,
brokerage fees, title costs, legal costs, recording costs, options to purchase
or lease interests and any other costs associated with the acquisitions of an
interest in current or possible production.
"Area of mutual interest" means, generally, an agreed upon area of land,
varying in size, included and described in an oil and gas exploration agreement
which participants agree will be subject to rights of first refusal as among
themselves, such that any participant acquiring any minerals, royalty,
overriding royalty, oil and gas leasehold estates or similar interests in the
designated area, is obligated to offer the other participants the opportunity to
purchase their agreed upon percentage share of the interest so acquired on the
same basis and cost as purchased by the acquiring participant. If the other
participants, after a specific time period, elect not to acquire their pro-rata
share, the acquiring participant is typically then free to retain or sell such
interests.
"Back-in interests" also referred to as a carried interest, involve the
transfer of interest in a property, with provision to the transferor to receive
a reversionary interest in the property after the occurrence of certain events.
"Bbl" means barrel, 42 U.S. gallons liquid volume, used in this annual
report in reference to crude oil or other liquid hydrocarbons.
"Bcf" means billion cubic feet, used in this annual report in reference to
gaseous hydrocarbons.
"BcfE" means billions of cubic feet of gas equivalent, determined using the
ratio of six thousand cubic feet of gas to one barrel of oil, condensate or gas
liquids.
"Casing point" means the point in time at which an election is made by
participants in a well whether to proceed with an attempt to complete the well
as a producer or to plug and abandon the well as a non-commercial dry hole. The
election is generally made after a well has been drilled to its objective depth
and an evaluation has been made from drill cutting samples, well logs, cores,
drill stem tests and other methods. If an affirmative election is made to
complete the well for production, production casing is then generally cemented
in the hole and completion operations are then commenced.
"Development costs" are costs incurred to drill, equip, or obtain access
to proved reserves. They include costs of drilling and equipment necessary to
get products to the point of sale and may entail on-site processing.
"Exploration costs" are costs incurred, either before or after the
acquisition of a property, to identify areas that may have potential reserves,
to examine specific areas considered to have potential reserves, to drill test
wells, and drill exploratory wells. Exploratory wells are wells drilled in
unproven areas. The identification of properties and examination of specific
areas will typically include geological and geophysical costs, also referred to
as G&G, which include topological studies, geographical and geophysical studies,
and costs to obtain access to properties under study. Depreciation of support
equipment, and the costs of carrying unproved acreage, delay rentals, ad valorem
property taxes, title defense costs, and lease or land record maintenance are
also classified as exploratory costs.
"Farmout" involves an entity's assignment of all or a part of its interest
in or lease of a property in exchange for consideration such as a royalty .
"Future net revenue, before income taxes" means an estimate of future net
revenue from a property, based on the production of the proven reserves of oil
and natural gas believed to be recoverable at a specified date, after deducting
production and ad valorem taxes, future capital costs and operating expenses,
before deducting income taxes. Future net revenue, before income taxes, should
not be construed as being the fair market value of the property.
2
"Future net revenue, net of income taxes" means an estimate of future net
revenue from a property, based on the proven reserves of oil and natural gas
believed to be recoverable at a specified date, after deducting production and
ad valorem taxes, future capital costs and operating expenses, net of income
taxes. Future net revenues, net of income taxes, should not be construed as
being the fair market value of the property.
"Mcf" means thousand cubic feet, used in this annual report to refer to
gaseous hydrocarbons.
"McfE" means thousands of cubic feet of gas equivalent, determined using
the ratio of six thousand cubic feet of gas to one barrel of oil, condensate or
gas liquids.
"MMcf" means million cubic feet, used in this annual report to refer to
gaseous hydrocarbons.
"MBbl" means thousand barrels, used in this annual report to refer to crude
oil or other liquid hydrocarbons.
"Gross" oil or gas well or "gross" acre is a well or acre in which Beta has
a working interest.
"Net" oil and gas wells or "net" acres are determined by multiplying
"gross" wells or acres by Beta's percentage interest in such wells or acres.
"Oil and gas lease" or "Lease" means an agreement between a mineral owner,
the lessor, and a lessee which conveys the right to the lessee to explore for
and produce oil and gas from the leased lands. Oil and gas leases usually have a
primary term during which the lessee must establish production of oil and or
gas. If production is established within the primary term, the term of the lease
generally continues in effect so long as production occurs on the lease. Leases
generally provide for a royalty to be paid to the lessor from the gross proceeds
from the sale of production.
"Overpressured reservoir" are reservoirs subject to abnormally high
pressure as a result of certain types of subsurface conditions.
"Present value of future net revenue, before income taxes" means future net
revenue, before income taxes, discounted at an annual rate of 10% to determine
their "present value." The present value is shown to indicate the effect of time
on the value of the revenue stream and should not be construed as being the fair
market value of the properties.
"Present value of future net revenue, net of income taxes" means future net
revenue, net of income taxes discounted at an annual rate of 10% to determine
their "present value." The present value is shown to indicate the effect of time
on the value of the revenue stream and should not be construed as being the fair
market value of the properties. Also known as the "Standardized Measure of
Discounted Future Net Cash Flows" if SEC pricing assumptions are used.
"Production costs" means operating expenses and severance and ad valorem
taxes on oil and gas production.
"Prospect" means a location where both geological and economical conditions
favor drilling a well.
"Proved oil and gas reserves" are the estimated quantities of crude oil,
natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e. prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions. Reservoirs are considered proved if
economic recovery by production is supported by either actual production or
conclusive formation test. The area of a reservoir considered proved includes
(A) that portion delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any, and (B) the immediately adjoining portions not yet drilled,
but which can reasonably be judged as economically productive on the basis of
available geological and engineering data. In the absence of information on
fluid contacts the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
3
"Proved developed oil and gas reserves" are those proved reserves that can
be expected to be recovered through existing wells with existing equipment and
operating methods. Additional oil and gas reserves expected to be obtained
through the application of fluid injection or other improved secondary or
tertiary recovery techniques for supplementing the natural forces and mechanisms
of primary recovery are included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed recovery
program has confirmed through production response that increased recovery will
be achieved.
"Proved undeveloped oil and gas reserves" are those proved reserves that
are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required. Reserves on
undrilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled. Proved reserves
for other undrilled units are claimed only where it can be demonstrated with
reasonable certainty that there is continuity of production from the existing
productive formation. Estimates for proved undeveloped reserves attributable to
any acreage do not include production for which an application of fluid
injection or other improved recovery technique is required or contemplated,
unless such techniques have been proved effective by actual tests in the area
and in the same reservoir.
"Reserve target" see "Prospect".
"Royalty interest" is a right to oil, gas, or other minerals that is not
burdened by the costs to develop or operate the related property.
"Seismic option" generally means an agreement in which the mineral owner
grants the right to acquire seismic data on the subject lands and grants an
option to acquire an oil and gas lease on the lands at a predetermined price.
"Trend" means a geographical area along which a petroleum pay occurs
(fairway).
"Working interest" is an interest in an oil and gas property that is
burdened with the costs of development and operation of the property.
4
Disclosure Regarding Forward-Looking Statements
Included in this report are forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements, other than
statements of historical facts, included in this Form 10-K which address
activities, events or developments which we expect or anticipate will or may
occur in the future are forward-looking statements. The words "believes,"
"intends," "expects," "anticipates," "projects," "estimates," "predicts" and
similar expressions are also intended to identify forward-looking statements.
Although we believe that the expectations reflected in such forward-looking
statements are reasonable, we can give no assurance that such expectations
reflected in such forward-looking statements will prove to have been correct.
All forward looking statements contained in this section are based on
assumptions believed to be reasonable.
These forward looking statements include statements regarding:
o Estimates of proved reserve quantities and net present values of those
reserves
o Reserve potential
o Business strategy
o Capital expenditures - amount and types
o Expansion and growth of our business and operations
o Expansion and development trends of the oil and gas industry
o Production of oil and gas reserves
o Exploration prospects
o Wells to be drilled, and drilling results
o Operating results and working capital
We can give no assurance that our expectations and assumptions will prove
to be correct. Reserve estimates of oil and gas properties are generally
different from the quantities of oil and natural gas that are ultimately
recovered or found. This is particularly true for estimates applied to
exploratory prospects and new production. Additionally, any forward-looking
statements are subject to various known and unknown risks, uncertainties and
contingencies, many of which are beyond our control. Such things may cause
actual results, performance, achievements or expectations to differ materially
from what we anticipated.
Factors that may affect such forward-looking statements include, but are
not limited to:
o Our ability to generate additional capital to complete our planned
drilling and exploration activities
o Risks inherent in oil and gas acquisitions, exploration, drilling,
development and production
o Oil and natural gas prices
o Competition from other oil and gas companies
o Shortages of equipment, services and supplies
o General economic, market or business conditions
o Economic, market or business conditions in the oil and gas industry and
in the energy business generally
o Government regulation
o Environmental matters
o Financial condition and operating performance of the other companies
participating in the exploration, development and
production of oil and gas ventures that we are involved in
In addition, since the majority of our prospects are currently operated by
third parties, we may not be in a position to control costs, safety and
timeliness of work as well as other critical factors affecting a producing well
or exploration and development activities.
5
Risk Factors
In order to fully explore our available prospects, we often will need to
sell fractional interests in those prospects to other parties who will share the
economic burdens and risks of our exploration efforts, or we will need to obtain
other financing for this purpose. Oil and gas leases have limited lives and
generally wells must be drilled within specified time periods in order to
preserve our rights under the lease. If we are unable to commence the
exploration operations in a timely manner on a lease, we may have to farmout or
abandon that lease.
Our operations are subject to the many risks and hazards incident to
drilling for, producing and transporting oil and gas, including blowouts, fires,
pollution and equipment failures. Such hazards may result in damage to or
destruction of wells, producing formations, production facilities and equipment
and personal injuries.
Of the producing wells in which we own a working interest, we are a
non-operating working interest owner in 42% of those wells and operate the
remaining 58%. Accordingly, we enter into joint operating agreements with third
parties relating to the conduct and supervision of drilling, completion and
production operations on the properties, including wells. The success of the oil
and gas exploration or development operations on a property depends in large
measure on whether the operator prudently performs its obligations. The failure
of an operator or its contractors to perform their services in a proper manner
could result in materially adverse consequences to the owners of interests in
that property.
We conduct only a perfunctory title examination at the time we acquire
properties believed to be suitable for exploration or development activities.
The operator usually conducts a more thorough title examination prior to the
commencement of drilling operations and curative work is then performed with
respect to known significant title defects. We depend upon formal title opinions
prepared at the request of the operator at or before the time production is
commenced; and, therefore, there can be no assurance that losses will not result
from title defects or from defects in the assignments of leasehold rights. The
operator of an oil and gas property is not liable to other interest owners for
losses due to title defects pursuant to industry standards for operating
agreements.
6
PART I
Item 1. Business of Beta
General
We are an independent oil and gas company engaged in the exploration,
exploitation, development, production and acquisition of natural gas and crude
oil. We are a Nevada corporation incorporated in June 1997. Our operations are
currently focused on the exploration and development of oil and gas producing
trends situated in Oklahoma, Texas, Louisiana and Kansas.
At December 31, 2001, we owned interests in approximately 318 gross wells,
187 wells net to our interest, in the Mid-Continent, Texas and Louisiana regions
and participated in the drilling and completion of 49 gross wells (11.57 net
wells) for the year. Additionally, we own interests in 31,000 net acres in
Kansas, Louisiana, Oklahoma, Texas and Wyoming plus a minority interest in a
West Queensland, Australia concession.
At December 31, our oil and gas properties had net proved reserves of 29.7
BcfE, comprised of 24.7 Bcf of natural gas and 836.8 MBbl of oil. From the first
quarter of 1999 through the fourth quarter of 2001, we have increased our
average net daily production from 205 McfE of natural gas to 9,866 McfE of
natural gas. For 2001, our production increased approximately 13% from a net
daily production of approximately 8,730 McfE at the end of 2000.
Business Strategy
Our overall goal is to maximize Beta's value through profitable growth in
our oil and gas reserves. We feel this can be achieved through the exploration
and development of our existing prospect inventory base located in the Gulf
Coast regions of Texas and Louisiana. As with any dynamic environment, we must
be flexible and adaptive to current economic and sector conditions in executing
our growth plan. In 2002, we will supplement our exploration and development
program with an acquisition program targeting properties that we believe possess
high development potential.
Following the 2000 acquisition of Red River Energy, LLC, we have a base
production level in place that can provide consistent cash flow to assist in
funding our exploration efforts. Exploration and development activities have
higher associated risks than those associated with acquisitions of producing
properties. Two of the largest risks associated with exploration and development
activities are:
o geological risks (the subject property does not hold recoverable oil or
natural gas);
o and project cost overruns.
By utilizing a "portfolio" approach in our exploration activities, we
expect to minimize the overall effect of these risks. We thus participate in a
larger number of exploratory and development activities by diversifying our
ownership positions. We utilize available advanced technology, such as
3-dimensional ("3-D") seismic modeling to further reduce risk and enhance our
success rates.
We believe that the availability of economical 3-D seismic surveys
fundamentally changed the risk profile of oil and gas exploration in certain
regions, specifically South Texas and Louisiana. Recognizing this, we have
aggressively sought to acquire significant acreage blocks in selected areas for
targeted, proprietary, 3-D seismic surveys. Using the data generated by initial
proprietary seismic surveys, covering over 300 square miles, we have identified
in excess of 200 potential drillsites net of 2001 activity. In general, when it
is not geographically advantageous for us to be the operator, we rely on
agreements with qualified operating oil and gas companies to operate many of our
projects through the exploratory and production phases.
7
Current Projects
TEXAS
Jackson County
Approximately $18.2 million has been expended since our inception in lease
acquisition, seismic and drilling activity in the onshore Jackson County, Texas
Gulf Coast region. Parallel Petroleum Corporation, Allegro Investments, Inc. and
Sue Ann Production, Inc operate the majority of our interests in the Jackson
County properties. Drilling commenced on these prospects during 1999 and has
resulted in a total of 28 (3.89 net) discoveries out of 41 (6.58 net) wells
drilled for a 68% (.59% net) success rate. During the year 2001, 14 exploratory
wells, (which resulted in 11 discoveries) and five development wells were
drilled. The leasing of acreage covering 12 deeper Wilcox prospects generated by
Beta was completed and drilling of two of those prospects commenced in 2001.
Frio/Yegua/Wilcox Trend 3-D Seismic Joint Venture, Jackson County, Texas
The Frio/Yegua/Wilcox Trend, onshore in South Texas, is our initial
cornerstone exploration area. Most of the positionn we acquired had never been
explored with the benefits of advanced 3-D seismic and other current
exploration, completion and production technologies.
In July 1997 Beta and various industry partners began assembling a 300+
square mile area in the heart of the Frio/Yegua/Wilcox trend, located in Jackson
County, Texas on which to conduct an advanced 3-D seismic survey. The survey was
conducted and, based on our review of the data approximately 44,000 acres remain
under lease for drilling.
From the 3-D seismic survey data, we identified over 200 prospective
drilling locations. Drilling commenced on this acreage in late 1999. Wells in
this prospect are usually placed on-line within a few weeks of completion and
have relatively low monthly operating expenses, thereby maximizing cash flow.
In early 2000, we engaged an independent reservoir evaluation firm to
review our existing seismic data and drilling results in the Frio/Yegua/Wilcox
trend in a 600 square mile area that encompasses Beta's acreage within this
trend. Since 1997, 152 wells had been drilled in the area by other parties with
over an 80% success rate. Of particular interest to us was that, over 40 of
these wells were drilled to the deep Yegua and Wilcox sands between 13,000 and
18,000 feet with 87% successfully completed as producing wells. Some Wilcox
fields in the trend have produced in excess of one TCF (trillion cubic feet) of
natural gas. We identified 12 Wilcox prospects in the trend and commenced
drilling those prospects in the latter half of 2001. For 2001, we participated
in the drilling of: (1) five gross Yegua wells (.625 net wells), of which three
were dry holes and two were completed in the shallower Frio sands, and (2) two
gross Wilcox wells (.14 net wells). One was a dry hold and one was completed and
producing in the Yegua formation. We had or will have an average 20% or less
working interest in these prospects and will not be the operator.
We presently own working interests in four Onshore Gulf Coast exploration
projects located in Jackson County, Texas. Approximately 47,892 gross acres,
approximately 11,110 net acres, of oil and gas leases have been acquired in
these four projects as of December 31, 2001. The operators completed 3-D seismic
surveys over an area totaling 286 square miles within which these projects are
located and continue to evaluate seismic data to select additional drilling
locations.
Geological and Economic Overview of the Frio/Yegua/Wilcox Trend 3-D Joint
Venture
The subject lands for the projects lie in close proximity to productive
oil and gas fields which produce from the Frio/Yegua/Wilcox intervals. We
emphasize that the historical production results in areas near these prospects
are not necessarily indicative of results that we may obtain from our oil and
gas prospects.
Within the four project areas, there are high potential exploration
opportunities that are being defined with the use of 3-D seismic. The Jackson
County, Texas area has proven to be suitable for 3-D seismic as faulting and
structures are easily identified and many stratigraphic reservoirs exhibit
hydrocarbon indicators from the shallowest Miocene sands, throughout the Frio,
and into the Vicksburg, Yegua, and Wilcox intervals. The Formosa Grande Prospect
Area has numerous regional down-to-the-coast faults that are easily identified
at the top of the Frio, but also has deep-seated faulting that does not exhibit
displacement at the shallower horizons. Very often, these deep faults do create
hydrocarbon traps. Most nearby producing fields in this trend area exhibit
multiple stacked reservoirs.
A Frio level structure map exhibits numerous large four-way closures,
primarily down-thrown to regional growth faulting. These large structures have,
for the most part, been exploited, some as early as the 1930s and 1940s.
Although it is not readily apparent in regional mapping, much of the Frio
production is stratigraphic in nature, that is, trapped in channel sands that
traverse structures, or in sands that "pinch out" up onto the flanks of these
large structures. Significant reserves may remain in similar traps, which have
not been developed to date. Such traps should be readily defined with 3-D
seismic data.
8
Our project areas appear to be located in a suitable "trend" area for 3-D
seismic technology to identify reserves that have been passed over in existing
fields as well as to discover new reserves in deeper pools and untested fault
segments in compartmentalized fields.
We believe this to be one of the best trends in the onshore Gulf Coast, and
recognize the potential benefit of this largeacreage position available for a
proprietary 3-D seismic survey. Given the drilling success rates in this trend,
we would find it more difficult to acquire our interest in the area today. We
believe this project provides somewhat lower risk, yet potentially highly
rewarding drilling for several years, as well as many high impact, deeper
projects.
Project Areas
The following projects in which we are participating will use the same
seismic techniques that the joint development group has previously used to
identify potential drill sites. Currently, our net daily average production for
the Jackson County wells is approximately 1,583 McfE of natural gas or 16% of
our current production. The status of each project is as follows:
a.) Texana Project. Approximately 25,000 gross acres under seismic
coverage; 13,520 gross acres under lease; 3,042 acres under lease net to Beta's
22.5 % working interest as of December 31, 2001: Approximately 40 square miles
of 3-D seismic data has been acquired and processed. "Amplitude Versus Offset"
analysis and data interpretation has been completed. Approximately 20 potential
locations, 15 Frio/Yegua and eight Wilcox, have been identified for drilling in
future periods. Drilling commenced in late 2000 with the first Yegua exploratory
well completed successfully in the Frio sands due to lack of a commercial Yegua
reservoir. The second exploratory well, the Elk Hills #1, is a Wilcox prospect
and commenced drilling in the fourth quarter of 2001. Testing of the Wilcox
formation is underway currently.
In 2001, we exchanged 2.5% in our Texana project for 2.5% in the Hilje
project located in Wharton County, Texas immediately to the east of Jackson
County. The interest was acquired from a third party working interest owner in
the Hilje area. We participated in the drilling of one well, the Marek #1, which
targeted the Wilcox sands. The well, which was operated by Pure Oil, was deemed
to be non-commercial.
b.) Formosa Grande Project. Approximately 92,000 gross acres under
seismic coverage; 3,932 gross acres under lease; 983 net acres under lease net
to Beta's 25% working interest at December 31, 2001: Approximately 140 square
miles of 3-D seismic data has been acquired. The seismic data has been
interpreted and prospects identified. Approximately 66 potential locations, 64
Frio and two Miocene, have been identified for drilling in future periods.
Six (1.5 net) shallow middle Frio exploratory wells were drilled in
2001, two (.5 net) were discoveries and four (1.0 net) were dry holes. The two
discoveries are collectively producing approximately 230 gross, (10 net), Mcf
per day.
c.) Ganado Project. Approximately 25,000 gross acres under seismic
coverage, 350 gross acres under lease; 71 acres under lease net to Beta's 20%
working interest at December 31, 2001: Approximately 40 square miles of 3-D
seismic data has been acquired and is in the interpretive stages. Approxi-mately
37 additional locations, 36 Frio/Vicksburg/Miocene and one Wilcox, have been
identified for drilling in future periods.
Drilling in this project commenced in mid-1999 and has resulted in four (.8
net) discoveries and two (.4 net) dry holes. In 2001, one (.2 net) development
well was successfully drilled and completed. Two (0 net) wells commenced
drilling the fourth quarter, in which we elected not to participate due to
project economics compared to other opportunities available. The two wells are
currently in the completion process.
d.) BWC Project. Approximately 42,440 gross acres under seismic
coverage, 16,610 gross acres under lease; 2,076 acres under lease net to Beta's
12.5% working interest at December 31, 2001: Approximately 66 square miles of
3-D seismic data has been acquired and is in the interpretive stage. Nine wells,
three Yegua and five Frio exploratory wells and one Frio development well, were
drilled in 2001. The three Yegua wells were unsuccessful but one was
successfully completed in the Frio sand. Three of the five Frio exploratory
wells were successful. The BWC discovery wells drilled in 2001 are currently
producing an average of 1,230 gross (155.1 net) Mcf of natural gas per day.
9
Approximately 110 prospects, 103 Frio/Yegua and seven Wilcox/Queen City,
in total have been identified for future drilling in this project. However, we
believe that within this 300-square mile proprietary 3-D survey, it is the
drilling in the deeper Wilcox formation that will have the greatest impact for
us.
e.) Mexican Sweetheart Project. 1,381 gross acres under lease; 497
acres under lease net to Beta's 36% working interest at December 31, 2000:
The prospect is located to the southeast of the Texana project and is a
deep Yegua test, which was based on 3-D seismic data. We would not maintain an
interest greater than 12.5% in this project. The drilling of this well is
projected for late 2002.
f.) Big Twelve Project. 8,758 gross acres under lease; 1,095 acres
under lease net to Beta's 12.5% working interest at December 31, 2000:
In 2001, we acquired a 12.5% interest in this project for $250,000 which
flanks our Mexican Sweetheart project to the north and our Texana project to the
west. A 19,000 Wilcox exploratory well was drilled in the last half of 2001. The
well did encounter Wilcox sands but it was evaluated as non-commercial. However,
it did prove up the Yegua formation and was successfully completed. The well
went on line in 1/2002 and is currently producing 1,400 gross (89 net) Mcf per
day.
Terms of Participation (Does not apply to Mexican Sweetheart)
All of the lands covered by the exploration agreements are subject to
provisions under which the parties each agree to offer a portion of any
interests within "areas of mutual interest" near the property being
acquired or explored to other parties to the agreement. The exploration
agreements generally also provide, among other things, for Beta and others in
each project to participate on the following terms and conditions:
Participants were required to pay 133% of the operator's actual cost
of initial land costs, consisting mainly of seismic options, and the costs of
acquiring, processing and interpreting seismic data. The 33% premium was paid to
unrelated parties as compensation for assembling the leases and conducting the
seismic operations. All costs incurred after the interpretation phase are billed
to the participants at actual cost, based on their working interest ownership.
The post- interpretation costs include the costs of acquiring leases, and the
cost of drilling, completing and equipping wells. Most of the projects are now
in the post-interpretive stage, however, data may be reprocessed to aid in
interpretation.
Once the seismic data has been acquired and interpreted, prospects are
identified and designated within the seismic survey areas. The parties to the
agreement then have the option to participate in the prospect according to their
pro-rata working interest. Those parties who elect not to participate forfeit
their rights of participation in the specific prospect but retain the right to
participate in other prospects proposed in the seismic survey area which are
outside of the specific prospect (excluding BWC project).
Those parties who elect to participate in a specific prospect then proceed
to acquire oil and gas leases within the prospect, usually by exercising seismic
options or leasing the desired properties. The seismic options were acquired in
advance of seismic acquisition and convey the right to conduct seismic
operations as well as the option to enter into an oil and gas lease on the
subject lands at a pre-determined price per acre with pre-established terms
allowing extension of the lease for various terms by payment of annual rentals.
The seismic option allows us, including our partners, to acquire and evaluate
seismic data before actually acquiring leases. After the seismic data has been
evaluated, Beta and its partners can then selectively acquire leases by
exercising on acreage that is determined to be prospective from seismic
evaluation. Seismic options covering lands, which are determined not to have oil
and gas potential, are allowed to expire at no further cost to the participants.
The cost of a seismic option is usually much lower than the cost of acquiring a
lease and it also prevents the mineral owner lessor from leasing the oil and gas
rights to another party during the term of the option.
Waller County
The Brookshire Dome Project
We have a joint exploration agreement with Revere Corporation (formerly
with Prime Natural Resources) to explore and exploit oil and gas potential
associated with the Brookshire Shallow Piercement Salt Dome located
10
approximately 30 miles west of Houston, Texas. In 2001, we increased our working
interest from 25% to 40% in the majority of our present Brookshire position. We
acquired an incremental 15% working interest in two producing properties and
certain leasehold acreage for a total cost of $579,000. Additionally we acquired
an additional working interest of 11.71% in three wells that were offsetting our
current Brookshire position for approximately $272,500. These purchases were
partially funded with proceeds from the sale of non-operating working interests
in non-strategic gas properties located in West Texas. For further discussion,
please see Item 8. Financial Statements, Note 2. Acquisitions And Dispositions
of Oil And Gas Operations.
This salt dome had been considered barren of economic reserves due to an
interpreted late growth history of the salt dome structure. In conjunction with
existing seismic data shot in 1982, which was recently reprocessed with state of
the art technology suggesting the possibility of sediments at depths of 4,000'
to 7,000' below a salt overhang, additional seismic was shot in late 2001 and is
currently in the final stages of processing.
Additional high technology interpretation of gravity data in conjunction
with the seismic and a surface geochemical survey further supports this concept.
Concurrent with this leasing activity, a series of successful shallow oil wells
were drilled and completed south of our acreage block. This production from
2,500' to 3,000' in Miocene aged sands above the salt is out of trend and given
the immaturity of the associated source rocks is considered by us to be
re-migrated from deeper reservoirs, probably up faults from beneath the salt.
These wells produce from 50 to 300 barrels of oil per day.
We have leased approximately 3,613 gross acres, 1,451 net acres, which are
favorably located to test sands that may lie in a hydrocarbon trapping position
below the salt. In the last half of 2001, an aggressive drilling program was
undertaken to further test the shallow sands potential. In 2001, we drilled 16
gross Miocene wells, nine exploratory and seven development wells. Of the
exploratory wells, we had six discoveries and three dry holes. Since 2000, we
have expended approximately $3.4 million on lease acquisition, geological and
geophysical and drilling of wells. The current daily production from our
Brookshire Dome area is approximately 817 gross (183 net) gross barrels of oil
and and 600 gross (180 net) Mcf. Drilling will re-commence in March 2002 with
the aid of the new seismic data.
Galveston County
The Greens Lake Project
The Greens Lake Prospect area, which lies in the Transition Zone of Texas
covering the shoreline and near shore environments in the Gulf of Mexico region,
is located approximately one mile southeast of the town site of Hitchcock in
Galveston County, Texas between Houston and the City of Galveston. Our working
interest is 34% and Ocean Energy, Inc. is the operator.
Two separate west and northwest dipping upthrown fault closed structures
have been delineated on the 5,500-acre lease block using downhole well control
and a 24 square-mile proprietary 3-D seismic shoot. Prospective sands range in
age from Miocene, Lower Frio, and Vicksburg. These two plays are actually deeper
sand structural test extensions of the prolific Big Gas Sand producing fields of
Sara White and North East Hitchcock and will be drilled to approximately 14,000
feet. Three prospects have been delineated within this project area, the Sara
White Prospect (to the south), the N.E. Hitchcock Prospect (to the north), and a
deep Vicksburg structure on trend with the one-half TCF Eagle Point field 10
miles to the northeast.
The Rubel #1 (Sara White Prospect), an apparent discovery, was spudded in
November 2001and is currently in the completion stage. Third party log analysis
recognizes 192 feet of net gas pay mostly concentrated in four pay sands.
Further evaluation is ongoing.
Red River and Lamar Counties
The Detroit Project
The Detroit project, covering 15,000 acres, is under lease in Red River and
Lamar Counties, Texas. The project was developed as a rework of existing seismic
and an extensive radiometric survey of the entire area for surface detection of
hydrocarbons. This large structural closure meets all the criteria for a major
reserve accumulation from the Arbuckle Group. The Arbuckle is overlaid by a
duplex structure involving the Jack Fork and Stanley formations similar to the
Potato Hills field in Oklahoma. To date we have expended approximately $942,000
for acreage, seismic and other geological and geophysical costs. We have a 75%
working interest in this prospect but will reduce our interest position to
recover some or all of our acreage cost and partially fund our share of drilling
cost. We plan to retain a 12.5% working interest.
11
LOUISIANA
Beta has invested approximately $12.8 million in leases, seismic data
collection and drilling in Louisiana. Drilling commenced on these prospects in
1998 and has resulted in six oil and gas discoveries so far. At present our net
daily average production in the transition area of Louisiana is approximately
1,035 McfE of natural gas.
In 2001, we participated in the drilling of three wells in the south
Louisiana area. The first well, the T.Cenac #1 located in Terrebonne Parish, was
completed in the Duval sand and went on line in September 2001 and is currently
producing approximately 8,000 gross Mcf (934 net Mcf) of natural gas per day and
140 gross barrels (15 net barrels) of condensate per day. The total cost
expended for the drilling and acreage was approximately $1.3 million. We have an
approximate 16.2% working interest in this area. The second well, the Dore #1
located in Vermillion Parish, was a 12,500 ft. exploratory test in the Live Oak
field and reached total depth subsequent to September 30, 2001. The test, in
which we had a 50% interest, proved unsuccessful and the well was plugged and
abandoned in October 2001. Our total cost including acreage, promote and dry
hole cost was approximately $734,000. In the last half of 2001, we drilled our
third exploratory well in Lafourche Parish which was an unsuccessful test.
We acquired leasehold positions in West Broussard, Lafayette Parish and
Lake Boeuf, Lafourche Parish.
The Lapeyrouse 3-D Project
The Lapeyrouse 3-D Project is located in Terrebone Parrish, Louisiana and
covers 1,969 gross acres and 295 net acres. Our working interest is 16.84% and
Xplor Energy, Inc. is the operator of the drilling activities. This project,
which is located in the prolific Gulf Coast Transition Zone of South Louisiana,
targets deeper untested formations, which we consider high potential, as well as
shallow development potential. The first well, the T.Cenac #1 as previously
discussed, commenced drilling in 2000 and was successfully completed in the
first quarter of 2001. Two more wells are planned for the last half of 2002.
The Lafourche Parish Project
The Raceland prospect is located in Lafourche Parish, Louisiana, in which
we own a working interest of approximately 7.5% was drilled in the last half of
2001. The high potential prospect consisted of two separate untested northwest
dipping fault closures and a large fault sealed ridge of significant untested
structural closure, downthrown on a large growth fault in the Lower Miocene
Robulus sands section. This structure, on 1,000 acres, was identified using all
well control, 2-D and 3-D proprietary seismic.
The test well, W. Ponson #1, commenced drilling in July 2001. The 16,800
ft. exploratory test for the Rob sands reached total depth and logged in early
October 2001. After a lengthy evaluation period, elections were made by the
working interest owners to abandon the well as non-commercial. Our total cost,
including acreage, was approxi-mately $562,000.
West Brousard Project, Lafayette Parish
We have also acquired evaluated and unevaluated acreage in the West
Broussard field. Approximately 1,100 leasehold acres were acquired in 2001 at a
cost of approximately $2.2 million. We have formed two offsetting 485-acre
units, to the east of existing production. As of December 31, 2001, we own
approximately 85% of the westernmost unit, which increased our total proved
reserves by approximately 8.1BcfE for 2001. The primary objective of this well
is the Bolmex 3 sand. Before drilling in mid to late 2002, we will reduce our
current working interest in this prospect to recover a portion or all of our
cost and fund a portion of our share of the drilling costs.
Lake Boeuf, Lafayette Parish
We have acquired 660 acres on a structural closure identified by 3-D
seismic. The prospect is within the overall producing outline of the Lake Beouf
field complex. A 15,800 ft. directional well will test six Rob L sands between
12,100 ft. and 13,200 ft. The well is expected to be drilled in the second half
of 2002. We have a total cost of approximately $230,000.
OKLAHOMA
In September 2000, we acquired Red River Energy, Inc. We issued 2,250,000
shares of its common stock valued at $14.355 million assuming a Beta common
stock price of $6.38. We acquired interests in over 230 wells, which included
145 operated wells in Oklahoma, Kansas and Texas. The acquisition significantly
increased our base production level and monthly cash flow from operations.
Please refer to Item 8. Financial Statements and Supplementary Data, Note 2.
Acquisitions And Dispositions of Oil And Gas Operations. Presently the net daily
average production for these properties is approximately 5,377 McfE of natural
gas.
12
In June 2000, prior to acquisition by us, Red River Energy acquired
interests in 124 properties and prospects in 26 fields located in Kansas,
Oklahoma and Texas from ONEOK Resources Company. The properties are
geographically distributed into three areas: Mid-Continent (17 fields), West
Texas (4 fields) and onshore Gulf Coast (5 fields). The package included 34
gross (30 net) operated oil wells, 3 gross (2 net) operated gas wells, 30 gross
(4 net) non-operated oil wells and 44 gross (7 net) non-operated gas wells. In
total, 74 gross wells are non-operated, or 67% of the total wells acquired. The
majority of the value is associated with the operated properties in the
Mid-Continent region.
WEHLU Project
The largest holding obtained through the Red River Energy acquisition was
the West Edmond Hunton Lime Unit (WEHLU), covering 30,000 acres (about 47 square
miles) primarily in Oklahoma County, Oklahoma. The field has 55 oil and natural
gas wells with stable production holding the entire unit. Beta holds a 98%WI and
is operator. At December 31, 2001, WEHLU had proven reserves of approximately 12
BcfE or approximately 43% of our total proven reserves. WEHLU currently produces
approximately 3,295 McfE per day or 33% of our current production.
The WEHLU Field, originally discovered in 1942, is the largest Hunton Lime
Field in the state, representing nearly 40% of the state's Hunton production. We
have an agreement with Avalon Exploration, Inc. of Tulsa, Oklahoma to jointly
test and develop additional production WEHLU with new re-completion and
stimulation methods.
To date, two wells have been drilled and a third is currently drilling in
the pilot program. The first well drilled tested the lower portion of the Hunton
and fluid recoveries were less than anticipated. A plug was set over the lower
interval and the upper Hunton has been tested and is currently producing
approximately 380 Mcf of natural gas, 5 barrels of oil and 65 barrels of water
per day. The second well drilled was not capable of commercial production and
has been plugged and abandoned. The third well is currently drilling and should
reach total depth by late March 2002.
While the first two wells of the pilot program did not produce the results
expected, they did not condemn the project either. It appears the dewatering of
the lower Hunton in this portion of the field may not work, so the scope of the
project has changed. The dewatering project may be proved up in another portion
of the field in the future.
Our joint development partner is anticipating finding primarily gas with
oil and water in future wells in the area it is drilling. They have two
additional drilling locations identified at this time. Under the terms of the
agreement, a minimum of four wells and a maximum of eight wells are to be
drilled for the pilot program in the field. The West Edmond Hunton Lime Unit is
a very large field and we are still optimistic that additional oil and gas will
be recovered through development drilling.
Charlie Project
The Charlie Prospect, coal bed methane properties also acquired in the
Red River Energy acquisition, has a current daily average production rate of 748
Mcf, a 50% percent increase for 2001. This property was given no value at the
time of the acquisition because the low production was used as collateral for a
non-recourse note. Since the acquisition, the note was extinguished and
production was stimulated in the existing wells. In 2001, three wells were
stimulated or reworked and an additional eight wells have been identified for
new fracturing stimulation in the future. At December 31, 2001, this project had
approximately 434 MMcf of proved reserves. We have a 100% working interest in
the project.
McIntosh County Project
We hold approximately 12,984 acres (9,497 net acres) of oil and gas
leases and have interests in 43 wells (27 net) and operate 34 of those wells in
the Hitchita Field. In 2001, we participated in the drilling of seven wells (six
discoveries and one dry hole) targeting the Atoka, Booch or Gilcrease sands.
With working interests in these wells ranging from 12.5% to 18.75%, a total of
approximately $400,000 was expended in 2001. The current production associated
from these wells is approximately 890 gross Mcf (120 net Mcf) of natural gas per
day.
The gas produced is dry and is sold into a low-pressure gathering system
of another wholly owned subsidiary, Red River Field Services, L.L.C. The
gathering system presently includes approximately 40 miles of pipeline and is
connected to 49 wells, including the wells in which we have an interest. During
2001, our gas gathering system in this area had gathering revenues of
approximately $868,000.
13
WYOMING
The Madden Field Project
In 2001, we purchased a 75% working interest in federal leases totaling
2,930 gross acres, (2,198 net acres) within the Madden Field located in Fremont
County, Wyoming in the Wind River Basin. We acquired the initial working
interest in 1,627 gross acres from Joe C. Richardson, Jr., a director of the
Company, for $154,800. (For further information on this transaction, please see
Item 13. Certain Relationships and Related Transactions.) This acreage offsets
three wells in the Lower Fort Union and Lance formations that have net pay
thickness of 1,090' to the south, 660' to the east, and 978' to the west. In
addition, we have options on 5,700 acres in the North Madden Area to the north
and 5,200 acres in the Birdseye Creek Area to the northwest.
With the decline in natural gas prices in the latter half of 2001, our
revised strategy for the Wind River Basin Project in Wyoming, which was
originally allocated $4.5 million for the exploration and development thereof,
is to farm out the prospect, and continue to evaluate the option acreage. In
2001, natural gas market conditions unfavorably impacted the Rocky Mountain area
with natural gas prices received in this area approximately $1.00 per Mmbtu
below the NYMEX - Henry Hub spot price. Currently, this pricing relationship has
improved and should enhance our current strategy. Based on the remaining term of
certain leases, we recognized $127,229 in impairment on this prospect and
transferred that amount to the full cost pool at December 31, 2001.
INTERNATIONAL
Australia
We are currently active in one prospect area located in West Queensland,
Australia on the Ethabuka structure. The projected drilling of a well would be
an offset to a well drilled in the 1970's but was abandoned due to drilling
difficulties. Tentatively, this well is scheduled to drill in 2002 pending the
placement of open working interests in the prospect. Tipperary Oil & Gas Pty,
LTD would be the operator of the well. It is anticipated we would participate
with an approximate 16% interest, which includes a 6% carried working interest.
Summary of Oil and Gas Operations
DRILLING ACTIVITY
For the period indicated, the following table sets forth the results of our
drilling activities in the fiscal years ended December 31, 2001, 2000 and 1999:
Years Ended December 31,
---------------------------------------------------
2001 2000 1999
Gross Net Gross Net Gross Net
----- ------- ------- ------- ----- -------
Exploratory:
Productive ............................... 19 4.40 14 2.24 12 1.75
Dry ...................................... 12 2.71 5 1.13 9 2.42
----- ------- ------- ------- ----- -------
Total Exploratory .................... 31 7.11 19 3.37 21 4.17
Development:
Productive ............................... 14 3.23 2 .26 -- --
Dry ...................................... 4 0.63 -- -- -- --
----- ------- ------- ------- ----- -------
Total Development .................... 18 3.86 2 .26 -- --
Total:
Productive ............................... 33 7.63 16 2.50 12 1.75
Dry ...................................... 16 3.34 5 1.13 9 2.42
----- ------- ------- ------- ----- -------
Total .................................. 49 10.97 21 3.63 21 4.17
===== ======= ======= ======= ===== =======
Subsequent to December 31, 2001, we have drilled 2 gross exploratory wells
and 0.6 net wells that are either completing or waiting completion.
14
PRICE AND PRODUCTION DATA
We commenced sales of oil and gas in 1999. Our average sales price, oil and
natural gas production volumes and average production cost for each Mcf
equivalent of production for the periods indicated were as follows:
Year Ended December 31,
------------------------------------------------
2001 2000 1999
------------- ------------- --------------
Oil production (Bbl) 114,271 32,614 1,822
Gas production (Mcf) 2,512,484 1,726,416 475,065
Average sales price:
Oil (per Bbl) $ 24.72 $ 30.57 $ 23.03
Gas (per Mcf) $ 3.97 $ 4.08 $ 2.44
Average production cost
per McfE $ 1.08 $ .71 $ 0.17
Reflects the impact of gas hedge which reduced our 2001 total average gas
price per Mcf by $0.25.
The above well information excludes five wells in which we have only a
royalty interest.
The components of production costs may vary substantially among wells
depending on the methods of recovery and other factors, but generally include
production and ad valorem taxes, repairs and maintenance, labor and utilities.
Capitalized costs at December 31, 2001, 2000 and 1999 relating to our oil
and gas activities are summarized as follows:
December 31, 2001 December 31, 2000 December 31, 1999
United States Foreign United States Foreign United States Foreign
------------- -------- ------------- ------- --------------- ---------
Capitalized costs-
Evaluated properties $ 57,027,523 $1,680,921 $ 42,717,576 $1,680,921 $ 8,128,928 $ 1,681,270
Unevaluated properties 12,872,623 128,820 13,326,778 123,569 11,973,532 118,095
----------------------------------------------------------------------------------
69,900,146 1,809,741 56,044,354 1,804,490 20,102,460 1,799,365
Less- Accumulated
depreciation, depletion,
amortization & impairment (23,377,455) (1,681,270) (4,714,056) (1,681,270) (2,115,957) (1,681,270)
-----------------------------------------------------------------------------------
$ 46,522,691 $ 128,471 $ 51,330,298 $ 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, 2001, 2000 and 1999 represent property acquisition and
exploration costs in connection with our Louisiana, Texas, Oklahoma and Wyoming
prospects. The prospects and their related costs in unevaluated properties have
been assessed individually. Costs associated with unevaluated leasehold,
including brokerage, are assessed annually based on the remaining term of the
primary leasehold. At December 31, 2001, unevaluated property, was impaired by
$1,272,836, which amount was transferred to U.S. evaluated costs, or the full
cost pool. The current status of the unevaluated prospects is that seismic has
been acquired, processed and is interpreted on a current and prospective basis
on the subject lands within the prospects. Drilling commenced on certain
prospects in the first quarter of 1999. As the prospects are evaluated through
drilling, the property acquisition and exploration costs associated with the
wells drilled are transferred to evaluated properties and become subject to
amortization.
Unevaluated oil and gas properties - Foreign
At December 31, 2001, unevaluated costs outside the United States,
represent costs in connection with the evaluation and cost of the Australian
concession.
Evaluated Properties - United States
The property acquisition and exploration costs associated with the wells
drilled (completed or plugged and abandoned) are transferred to evaluated
properties. In 2001, we participated in the drilling of 49 wells within the
United States. At December 31, 2001 and at September 30, 2001, total cost in
evaluated properties exceeded their net realizable value. A total full cost
impairment of $13,805,035 was recognized in 2001. Depletion expense of
$4,858,364 was recorded in 2001. For further discussion, please refer to Item 8.
Financial Statements and Supplementary Data, Note 2. Acquisitions And
Dispositions of Oil And Gas Operations.
15
At December 31, 2000, evaluated property cost was $44,398,497 which
included $28,371,531 associated with the Red River Energy acquisition. In 2000,
we participated in the drilling of 21 wells within the United States. No
impairment was recorded for 2000. Depletion expense of $2,604,628 was recorded
in 2000.
At December 31, 1999, it was determined that the total costs for evaluated
properties of $8,128,928 exceeded their net realizable value by $1,167,910.
Accordingly, an impairment charge for this amount was recorded for the year
ended December 31, 1999. Production commenced during the period and depletion
expense of $901,573 was recorded.
Evaluated Properties - Foreign
During 1998, Beta, through its wholly owned subsidiary, BETAustralia, LLC
secured an option to participate for a 5% working interest in two petroleum
licenses covering 2,798,000 acres (approximately 4,372 square miles). Per the
terms of the option agreement, Beta exercised its option to earn a 5% working
interest by participating in the drilling of two offshore test wells in the
license areas. The wells were completed as dry holes. The property acquisition
and exploration costs associated therewith totaling $1,624,218 were transferred
to evaluated properties and charged to impairment expense during the year ended
December 31, 1998. The exploration licenses expired in December 1998. Property
acquisition and exploration costs associated with foreign prospects totaling
$57,052 were transferred to evaluated properties and charged to impairment
expense during the year ended December 31, 1999. Beta has generated no revenues
from its foreign properties to date.
For further information on oil and gas operations, please see Item 8.
Financial Statements and Supplementary Data, Note 2. Acquisitions And
Dispositions of Oil And Gas Operations.
Principal Products
Our principal products are natural gas and crude oil.
Patents, Trademarks, Licenses, Franchises and Concessions Held
Permits, licenses and oil and gas leases are important to our operations,
as they allow the search for the extraction of any oil, gas and minerals
discovered on the areas covered. See further, Item 2 herein.
Seasonality of Business
Weather conditions affect the demand for and prices of natural gas and can
also delay drilling activities, disrupting our overall business plans. Demand
for natural gas is typically higher in the fourth and first quarters resulting
in higher natural gas prices. Due to these seasonal fluctuations, results of
operations for individual quarterly periods may not be indicative of results
which may be realized on an annual basis.
Markets and Customers
Our oil and gas production is sold at the well site on an as-produced basis
at market-related prices in the areas where the producing properties are
located. We do not refine or process any of the oil or natural gas we produce
and approximately 95% or our production is sold to unaffiliated purchasers on a
month-to-month basis.
In the table below, we show the purchasers that each accounted for 10% or
more of our revenue during the specified years.
2001 2000
----------------- -----------------
IP Petroleum (Pure) 8% 31%
Duke Energy 29% 19%
Cokinos Energy 5% 13%
Allegro Investments 16% 12%
16
We do not believe the loss of any one of our purchasers would materially
affect our ability to sell the oil and gas we produce. Other purchasers are
available in our areas of operations. We had no direct sales contracts or
derivatives with the Enron Corporation ("Enron"). Genesis Crude Oil, LP, a
purchaser of our crude oil for the Brookshire Dome area, did re-sell one month
(November 2001) of crude oil production to a subsidiary of Enron. However, at
this time we have received payment from Genesis for that month and are not aware
of any adverse effect on Genesis. We cannot guarantee that through the re-sale
process there may be other situations similar to the one previously discussed
but we are not aware of any additional dealings with Enron at this date.
The marketability of our current oil and gas reserves or of reserves which
we may acquire or discover may be affected by numerous factors beyond our
control. These factors include fluctuations in product markets and prices, the
proximity and capacity of pipelines to our oil and gas reserves, our ability to
finance exploration and development costs and the availability of processing
equipment. Additional factors are engineering and construction delays,
difficulties and hazards resulting from unusual or unexpected geological or
environmental conditions, or to the conditions involved in drilling and
operating wells.
We are not obligated to provide a fixed and determinable quantity of oil or
natural gas under any existing arrangements or contracts. We expect to use hedge
arrangements on a limited basis as necessary to partially protect against
commodity volatility.
Our business does not require us to maintain a backlog of products,
customer orders or inventory.
Competitive Conditions in the Business
The petroleum and natural gas industry is highly competitive and we compete
with a substantial number of other companies that have greater resources. Many
such companies not only explore for, produce and market petroleum and natural
gas but also carry on refining operations and market the resultant products on a
worldwide basis. There is also competition between petroleum and natural gas
producers and other industries producing energy and fuel. Furthermore,
competitive conditions may be substantially affected by various forms of energy
legislation and/or regulation considered from time to time by the governments
(and/or agencies thereof) of the United States and Canada; however, it is not
possible to predict the nature of any such legislation and/or regulation which
may ultimately be adopted or its effects upon our future operations. Such laws
and regulations may, however, substantially increase the costs of exploring for,
developing or producing oil and gas and may prevent or delay the commencement or
continuation of a given operation. The exact effect of these risk factors cannot
be accurately predicted.
Oil and gas exploration and development involves a high degree of risk,
which even a combination of experience, knowledge and careful evaluation may not
be able to overcome. There is no assurance that we will discover or acquire
additional oil and gas in commercial quantities. Oil and gas operations also
involve the risk that well fires, blowouts, equipment failure, human error and
other circumstances may cause accidental leakage of toxic or hazardous
materials, such as petroleum liquids or drilling fluids into the environment, or
cause significant injury to persons or property. In such event, substantial
liabilities to third parties or governmental entities may be incurred, the
payment of which could substantially reduce available cash and possibly result
in loss of oil and gas properties. Such hazards may also cause damage to or
destruction of wells, producing formations, production facilities and pipeline
or other processing facilities.
As is common in the oil and gas industry, we will not insure fully against
all risks associated with our business either because such insurance is not
available or because premium costs are considered prohibitive. A loss not fully
covered by insurance could have a materially adverse effect on our financial
position and results of operations.
Regulations
Domestic exploration for, and production and sale of, oil and gas are
extensively regulated at both the federal and state levels. Legislation
affecting the oil and gas industry is under constant review for amendment or
expansion, frequently increasing the regulatory burden. Also, numerous
departments and agencies, both federal and state, are authorized by statute to
issue, and have issued, rules and regulations binding on the oil and gas
industry that often are costly to comply with and that carry substantial
penalties for failure to comply. In addition, production operations are affected
by changing tax and other laws relating to the petroleum industry, by constantly
changing administrative regulations and possible interruptions or termination by
government authorities.
17
State regulatory authorities have established rules and regulations
requiring permits for drilling operations, drilling bonds and reports concerning
operations. Most states in which we operate also have statutes and regulations
governing a number of environmental and conservation matters, including the
unitization or pooling of oil and gas properties and establishment of maximum
rates of production from oil and gas wells. Many states also restrict production
to the market demand for oil and gas. Such statutes and regulations may limit
the rate at which oil and gas could otherwise be produced from our properties.
We are subject to extensive and evolving environmental laws and
regulations. These regulations are administered by the United States
Environmental Protection Agency ("EPA") and various other federal, state, and
local environmental, zoning, health and safety agencies, many of which
periodically examine our operations to monitor compliance with such laws and
regulations. These regulations govern the release of waste materials into the
environment, or otherwise relating to the protection of the environment, human,
animal and plant health, and affect our operations and costs. In recent years,
environmental regulations have taken a "cradle to grave" approach to waste
management, regulating and creating liabilities for the waste at its inception
to final disposition. Our oil and gas exploration, development and production
operations are subject to numerous environmental programs, some of which include
solid and hazardous waste management, water protection, air emission controls,
and situs controls affecting wetlands, coastal operations, and antiquities.
Environmental programs typically regulate the permitting, construction and
operations of a facility. Many factors, including public perception, can
materially impact the ability to secure an environmental construction or
operation permit. Once operational, enforcement measures can include significant
civil penalties for regulatory violations regardless of intent. Under
appropriate circumstances, an administrative agency can request a "cease and
desist" order to terminate operations.
New programs and changes in existing programs are anticipated, some of
which include Natural Occurring Radioactive Materials ("NORM"), oil and gas
exploration and production waste management, and underground injection of waste
materials.
Each state in which we operate has laws and regulations governing solid
waste disposal, water and air pollution. Many states also have regulations
governing oil and gas exploration, development and production operations.
We are also subject to Federal and State Hazard Communications ("OSHA") and
Community Right to Know ("SARA Title III") statutes and regulations. These
regulations govern record keeping and reporting of the use and release of
hazardous substances. We believe we are in compliance with these requirements in
all material respects.
We may be required in the future to make substantial outlays to comply with
environmental laws and regulations. The additional changes in operating
procedures and expenditures required to comply with future laws dealing with the
protection of the environment cannot be predicted.
Employees
As of the date of this annual report, we employ 19 full-time employees. We
hire independent contractors on an "as needed" basis. We have no collective
bargaining agreements with our employees. We believe that our employee
relationships are satisfactory.
Premises
We lease approximately 6,400 square feet in Tulsa, Oklahoma, which includes
offices and storage space. All of our corporate functions and some operational
functions are conducted from this site. The lease expires January 2004, and
requires monthly payments of approximately $9,300 per month. A regional Gulf
Coast office is also maintained in Houston, Texas under an office sharing
arrangement and requires monthly payments of approximately $2,744. This
renewable arrangement expires March 2003. We also own two field offices located
in South Tulsa County and Edmond, Oklahoma.
18
Item 2. Properties of Beta
General:
Our principal properties consist of developed and undeveloped oil and gas
leases and the reserves associated with these leases. Generally, developed oil
and gas leases remain in force so long as production is maintained. Undeveloped
oil and gas leaseholds are generally for a primary term of three to five years.
In most cases, the term of our undeveloped leases can be extended by paying
delay rentals or by producing reserves that are discovered under our leases. Our
revolving credit facility is collateralized by the reserves associated with our
proved producing properties and our producing oil and gas properties.
PRODUCTIVE WELLS AND ACREAGE
We have presented the following table to provide you with a summary of the
producing oil and gas wells and the developed and undeveloped acreage in which
we owned an interest at December 31, 2001. We have not included in the table,
acreage in which our interest is limited to options to acquire leasehold
interests, royalty or similar interests.
Producing Wells Acreage
---------------------------------------------- ---------------------------------------------------------
Oil Gas Developed Undeveloped
Gross Net (1) Gross Net (1) Gross Net (2) Gross Net
------- --------- -------- --------- ----------- ----------- ----------- -----------
Texas 19 4.69 47 7.44 23,781.3 1,619.0 68,643.2 24,723.3
Oklahoma 71 50.51 126 81.41 55,600.9 42,333.4 1,608.4 877.0
Louisiana 1 0.12 10 0.89 8,046.7 909.3 12,111.0 2,807.6
Kansas 19 18.79 2 2.00 6,889.4 3,681.1 640.0 640.0
California - - - - 318.6 95.6 - -
Wyoming - - - - - - 2,930.0 2,197.5
------- --------- -------- --------- ----------- ----------- ----------- -----------
110 74.11 185 91.74 94,636.9 48,638.4 85,932.6 31,245.4
======= ========= ======== ========= =========== =========== =========== ===========
(1) Net wells are computed by multiplying the number of gross wells by our
working interest in the gross wells.
(2) Net acres are computed by multiplying the number of gross acres by our
working interest in the gross acres.
At December 31, 2001, approximately 19,022.1 gross acres and 5,915.6 net
acres will expire in 2002.
In addition to the interests we own in developed and undeveloped acreage,
at December 31, 2001 we have options to acquire interest in: 1.) an additional
10,032 gross (3,344 net) acres in Jackson County, Texas which expire April 16,
2002; and 2.) an additional 13,800 gross (10,350 net) acres in Fremont County,
Wyoming, which expire May 3, 2002. We do not expect to renew these options.
OIL AND NATURAL GAS RESERVES
At December 31, 2001, we had proved reserves of 836.8 Mbbls of oil and 24.7
Bcf of gas as estimated by Ryder Scott and Company, an independent engineering
firm. These reserves are located entirely within the United States. The
following table sets forth, at December 31, 2001, the present value of our
future net revenues (revenues less production and development cost) before
income taxes attributable to these reserves.
Proved Proved
Developed Undeveloped Total Proved
------------ ------------- --------------
Oil (Bbls) 707,751 129,077 836,828
Gas (Mcf) 16,654,000 8,056,000 24,710,000
Future Net Revenues (before income taxes) $ 34,044,799 $ 12,512,378 $ 46,557,177
============ ============= ==============
Present value of Future Net Revenue
(before income taxes) $ 21,677,411 $ 9,617,601 $ 31,295,012
============ ============= ==============
Present value of Future Net Revenue
(after income taxes) $ 21,677,411 $ 9,617,601 $ 31,295,012
============ ============= ==============
19
The above figures do not reflect the future net revenues before income
taxes and the present value of future net revenues, discounted at 10%, for our
McIntosh gathering system, which were $858,199 and $670,579, respectively.
For purposes of estimating the above cash flows, estimates were made of
quantities of proved reserves and the periods during which they are expected to
produce. Future cash flows were computed by applying year-end prices to
estimated annual future production from proved oil and gas reserves. The average
year-end price for oil and natural gas was $18.17/Bbl and $2.65/Mcf at December
31, 2001. Future development and production costs were computed by applying
year-end costs to be incurred in producing and further developing the proved
reserves. The estimated future net revenue was computed by application of a 10%
discount factor. The calculations assume the continuation of existing economic,
operating and contractual conditions. However, such arbitrary assumptions have
not proven to be the case in the past. Other assumptions of equal validity could
give rise to substantially different results.
For additional information on our oil and gas reserves, please refer to
Item 8. Financial Statements And Supplementary Data, Note 13. Unaudited
Supplementary Oil And Natural Gas Information.
Our oil and gas reserves are not subject to any long-term supply
arrangement with foreign governments or authorities. Our estimated reserves have
not been filed with or included in reports to any federal agency other than the
SEC and U.S. Department of Energy, FORM EIA-23, Annual Survey of Domestic Oil
and Gas Reserves for 2001.
Item 3. Legal Proceedings
On November 29, 2000 in the District Court of Tulsa County, State of
Oklahoma, a Petition was filed by ONEOK Energy Marketing and Trading Company,
L.P. ("ONEOK"), plaintiffs, naming the Company and two wholly-owned
subsidiaries, Red River Field Services, L.L.C. and Red River Energy, L.L.C.
("Beta"), as defendants. In the lawsuit, plaintiff alleges that Beta
discontinued selling gas to plaintiff in breach of a fixed price agreement and
sold the gas instead to other suppliers. Beta counterclaimed on January 24,
2001, alleging that the contract had been terminated pursuant to its terms for
nonpayment by plaintiff for gas supplied prior to termination, and seeking
damages for the unpaid charges of $282,096.
Subsequent to December 31, 2001, we have settled the above claim and
counterclaim with ONEOK through independent mediation. It was mutually agreed to
release all claims and Beta will pay ONEOK $43,000 in addition to the $282,096
of funds currently held by ONEOK. Each party will be responsible for their legal
fees and costs associated with this matter of which our total legal fees were
approximately $85,600. In regards to this settlement, a non-recurring charge of
$205,415 was recorded to income in the year ended December 31, 2001. However,
the total net impact, including the impact of the non-recurring charge was a
favorable $60,000 in additional net gas revenues due to our counterclaim.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of our shareholders during the fourth
quarter of the fiscal year ended December 31, 2001.
20
PART II
Item 5. Market Price for Registrant's Common Equity and Related Stockholder
Matters
Our common stock began trading July 9, 1999 on the Nasdaq Small Cap Market
under the symbol "BETA". On May 4, 2000 we were accepted on the Nasdaq National
Market. The following table sets forth for the fiscal periods indicated the
range of the high and low sale prices of our common stock as reported on the
Nasdaq Small Cap Market for the 1st quarter of 2000 and the Nasdaq National
Market for the remaining three quarters of 2000. and for the all quarters in
2001. We have not paid any cash or other dividends since inception. For the
foreseeable future, we intend to retain any funds otherwise available for
dividends.
2001 High Low
---- ---- ----
1st Quarter....... $ 9.13 $ 6.75
2nd Quarter...... 8.83 6.56
3rd Quarter...... 8.06 4.95
4th Quarter....... 6.45 3.80
2000
1st Quarter....... $ 10.56 $ 6.53
2nd Quarter...... 10.88 7.75
3rd Quarter...... 12.00 7.75
4th Quarter....... 9.38 6.81
Approximately 232 shareholders of record and approximately 2,220 beneficial
owners as of March 15, 2002 held the common stock. In many instances, a
registered shareholder is a broker or other entity holding shares in street name
for one or more customers who beneficially own the shares.
21
Item 6. Selected Financial Data
Summary Financial Information for Beta
The following tables presents selected historical financial data derived
from our Financial Statements as well as selected historical quarterly financial
data. The following data is only a summary and should be read with our
historical financial statements and related notes contained in this document.
The acquisition of Red River Energy,Inc. in 2000 affects the comparability
between the Financial Data for the periods presented.
For the years ended December 31, The period from
inception (June
6,1997 through
2001 2000 1999 1998 December 1997)
------------- ------------- ------------ --------- -------------
Income Statement Data:
Operating revenues ............ $ 13,656,521 $ 8,357,867 $ 1,199,480 $ -- $ --
Operating expense 3,808,523 1,516,113 81,538 -- --
General and administrative .... 2,679,121 2,141,005 1,418,240 746,769 245,452
Impairment expense ............ 13,805,035 -- 1,224,962 1,670,691 --
Depreciation and depletion expense 5,176,897 2,693,439 914,233 11,883 1,530
Interest expense 867,835 393,008 2,966,651 -- --
Net income (loss) (9,046,084) 1,425,565 (5,384,403) (2,384,500) (201,573)
Earnings (loss) per share:
Basic ......................... $ (.75) $ .134 $ (.66) $ (.37) $ (.05)
Diluted (.75) .126 (.66) (.37) (.05)
Weighted average common shares and equivalent outstanding:
Basic 12,368,373 10,616,692 8,160,000 6,366,923 4,172,662
Diluted 12,368,373 11,281,413 8,160,000 6,366,923 4,172,662
Balance sheet data:
Working capital $ (103,550) $ 3,533,237 $ 2,034,268 $ (96,457) $3,117,351
Total assets ...................... 52,629,378 58,466,152 20,881,475 13,618,471 9,921,057
Total long term debt .............. 13,648,727 13,814,034 27,939 -- --
Stockholder's equity .............. 35,874,474 40,060,406 20,588,237 13,299,342 9,050,210
Proved Reserves
Oil (Mbbls) 836.8 814.0 13.2 1.4 --
Gas (Mmcf) 24,710.0 19,418.0 4,170.0 1,596.7 --
Total (Mmcfe) 29,730.8 24,302.0 4,249.2 1,605.1 --
Present value of estimate future
net revenues before income tax
discounted at 10% ...................... $ 31,295,012 $ 100,199,288 $ 6,012,972 $ 1,716,608 $ --
============= ============= ============= ============== =========
Standardized measure ................... $ 31,295,012 $ 71,458,654 $ 6,012,972 $ 1,716,608 $ --
============= ============= ============= ============== =========
22
SELECTED QUARTERLY For the quarter ended
FINANCIAL DATA -------------------------------------------------------------
(In Thousands of Dollars) March 31 June 30 September 30 December 31
-------------- ------------- --------------- ----------------
2001
Revenues $ 4,696.1 $ 3,809.6 $ 2,531.3 $ 2,619.5
Revenues less operating expense 3,748.5 2,926.5 1,623.7 1,549.3
Net income (loss) 905.7 388.0 (4,657.0) (5,682.9)
Earnings (loss) per share:
Basic .07 .03 (.39) (.46)
Diluted .07 .03 (.39) (.46)
2000
Revenues $ 940.3 $ 1,082.3 $ 2,022.8 $ 4,312.5
Revenues less operating expense 906.4 959.8 1,689.5 3,286.1
Net income (loss) (125.4) (50.5) 840.4 761.1
Earnings (loss) per share:
Basic (0.01) (0.01) 0.08 0.06
Diluted (0.01) (0.01) 0.07 0.06
1999
Revenues 29.7 91.6 254.3 823.9
Revenue less operating expense 20.7 88.7 242.1 766.9
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)
23
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion is to inform you about our financial position,
liquidity and capital resources as of December 31, 2001 and 2000, and the
results of operations for the years ended December 31, 2001, 2000 and 1999.
General
During 2001, our economy slipped into a recession due to weakened demand for
products creating surplus inventories in a majority of business sectors. The
energy sector, which was not an exception, experienced a significant decline in
demand and consequently inventory levels for both natural gas and crude oil
materially increased over the previous year's inventory levels. With the
significant build up of inventory by mid-2001, commodity prices for natural gas
and crude oil decreased approximately 75% and 30%, respectively, from the
beginning of the year. Demand for drilling has significantly decreased during
the last half of 2001 with a decrease in exploration activity.
Liquidity and Capital Resources
A company's liquidity is the amount of time expected to elapse until an
asset can be converted to cash or conversely until a liability has to be paid.
Liquidity is one indication of a company's ability to meet its obligations or
commitment. Historically, our major sources of liquidity have come from
internally generated cash flow from operations, funds generated from the
exercise of warrants/options and proceeds from public and private stock
offerings.
The following table represents the sources and uses of cash for the years
indicated.
For the years ended December 31,
2001 2000 1999
--------------- ------------- --------------
Beginning cash balance $ 1,536,186 $ 1,448,655 $ 198,043
Sources of cash:
Cash provided by (used in) operations 9,047,095 3,229,081 (1,262,655)
Cash provided by financing activities 4,720,958 2,900,170 9,759,960
Cash provided by sales of oil & gas properties and
equipment 1,082,524 100,000
Cash provided from acquisition - 895,097 -
--------------- ------------- --------------
Total sources of cash including cash on 16,386,763 8,573,003 8,695,348
hand
Uses of cash:
Oil and gas expenditures (14,927,031) (6,666,327) (6,945,695)
Other assets (including advance to industry partners) (903,533) (370,490) (300,998)
--------------- ------------- --------------
Total uses of cash (15,830,564) (7,036,817) (7,246,693)
--------------- ------------- --------------
Ending cash balance $ 556,199 $ 1,536,186 $ 1,448,655
=============== ============= ==============
Our working capital was a deficit of ($103,550) at December 31, 2001
compared to surpluses of $3,533,237 at December 31, 2000 and $2,034,268 at
December 31, 1999. The significant decrease to our working capital was due to
higher capital expenditures associated with our intensified drilling and lease
acquisition activity principally occurring in the last half of 2001. Our capital
program was funded from: 1.) cash flow from operations, 2.) funds received from
our preferred stock private placement, and 3.) proceeds from the sale of certain
evaluated and unevaluated oil and gas properties. Approximately $15.1 million
was expended during the year on our exploration and development program,
including the acquisition of additional working interests in production and
leasehold acreage, both evaluated and unevaluated. Approximately $4.4 million
was expended in the fourth quarter on additional lease acquisition in our West
Broussard area and the drilling of: 1.) the Signal Hill #1 - Big Twelve Wilcox
test well, 2.) the Ponson #1 - Raceland "S" sand test well, 3.) the Elk Hills #1
- - Texana Wilcox test well, 4.) the Rubel #1 - Sara White test well, and 5.) 11
test or development wells in the Brookshire Dome area. For the year our results
from our exploration program have been disappointing in regards to the discovery
of any significant field or extensions.
24
However, we have increased proved reserves for 2001 by 5.4 BcfE or 22%,
which was primarily the result of the completion of leasing and the unitization
of our West Broussard prospect which added approximately 8.1 BcfE of proved
undeveloped reserves. Our proved developed reserves declined by 3.1 BcfE or 13%.
Our proved developed discoveries were offset by the current year's production
and downward revision of reserves. This was due to lower commodity prices,
higher operating expenses associated with our WEHLU production and downward
volume revision due to lack of production history, related to the Brookshire
Dome area.
Our liquidity has been significantly reduced during the year by our
aggressive drilling and exploration program and a significant decrease in
natural gas and crude oil prices. Our principal source of short-term liquidity
is from operating cash flow. Should natural gas and crude oil prices decrease
further, our current operating cash flow would decrease and further reduce our
liquidity. Our short-term liquidity and working capital should increase in the
first quarter of 2002 due to a significant decrease in capital expenditures as
our late 2001 drilling projects near completion and lower overall drilling
activity. An additional source of short-term liquidity will be funds received
from the reduction of our interests in certain unevaluated or proved undeveloped
projects. To date, subsequent to December 31, 2001, we have received
approximately $585,400 from the sale of interests in our West Broussard, Lake
Boeuf and North Mexican Sweetheart prospects. We intend to further reduce our
working interest in these and other unevaluated projects to enhance our risk
profile and raise additional working capital for our 2002 capital program and
debt reduction.
In 2001,with the decline of commodity prices and a reduction in our proved
developed reserves, our borrowing base capacity under the current credit
facility, which was acquired through the Red River Energy acquisition, has not
increased and is not a material source of capital. However, historically we have
not used credit facilities for a source of funds in our drilling or leasing
activity. Should proved developed reserves not materially increase and/or
pricing further decline, our borrowing base may be reduced below the amount
currently borrowed and outstanding under this facility. If this event occurs we
would be obligated to pay down the outstanding amount to the re-determined
borrowing capacity. We would rely on cash flow from operations and funds
generated from the sale of unevaluated or proved undeveloped prospects to make
this pay down. The next re-determination will take place in April 2002.
Long Term Liquidity and Capital Resources
We have no material long-term commitments associated with our capital
expenditure plans or operating agreements. Consequently, we have a significant
degree of flexibility to adjust the level of such expenditures as circumstances
warrant. The level of capital expenditures will vary in future periods depending
on the success we have with our exploratory drilling activities in future
periods, gas and oil price conditions and other related economic factors. The
following tables show our contractual obligations and commitments.
Payments Due by Period
----------------------------------------------------------------------------------
Contractual Obligations Total Less than 1 1-3 years 4-5 years After 5 years
year
---------------- --------------- ---------------- ---------------- ---------------
Long - Term Debt (1) $13,706,134 $ 57,407 $13,648,727 $ - $ -
Operating Leases (2) 367,937 179,068 188,869 - -
---------------- --------------- ---------------- ---------------- ---------------
Total cash obligations $14,074,071 $ 236,475 $13,837,596 $ - $ -
================ =============== ================ ================ ===============
(1) $13,634,652 is related to our current credit agreement with a
commercial bank. For further information please refer to Item
8. Financial Statements and Supplement Data, Note 4, Long Term Debt.
(2) Represents amounts due under current operating lease agreements
including the office rental agreement.
Amount of Commitment Expiration per Period
-----------------------------------------------------------------------------------
Other Commercial Total Less than 1 1-3 years 4-5 years After 5 years
Commitments year
----------------- --------------- ----------------- --------------- ---------------
Standby letters of
credit $ 108,500 $108,500 - - -
25
We currently have no sources of liquidity or financing that are provided by
off-balance sheet arrangements or transactions with unconsolidated, limited
purpose entities.
Accounting Policies
We rely on certain accounting policies in the preparation of our financial
statements. Certain judgments and uncertainties affect the application of such
policies. The "critical accounting policies" which we use are as follows:
o Use of estimates
o Oil and gas properties
o Derivative instruments and hedging activity
o Concentration of credit risk
Certain accounting principals are employed in the adherence and
implementation of these policies along with management judgments. We will
address each policy and how certain judgments and/or uncertainties could
materially impact these policies.
Use of Estimates - The preparation of the our consolidated financial
statements in conformity with generally accepted accounting principles requires
our management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities, if any, at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. The estimates
include oil and gas reserve quantities, which form the basis for the calculation
of amortization and impairment of oil and gas properties. We emphasize that
reserve estimates are inherently imprecise and that estimates of more recent
discoveries are more imprecise than those for properties with long production
histories. Actual results could materially differ from these estimates.
Volatility in commodity prices also impacts reserve estimates since future
revenues from production may decline significantly if there is a material
decrease in natural gas and/or crude oil prices from the previous reserve
estimation date, which is at each quarter end.
Oil and gas properties - We account for our oil and gas producing
activities using the full cost method of accounting as prescribed by the United
States Securities and Exchange Commission ("SEC"). Accordingly, all costs
incurred in the acquisition, exploration, and development of proved oil and gas
properties, including the costs of abandoned properties, dry holes, geophysical
costs, and annual lease rentals are capitalized. All general corporate costs are
expensed as incurred. In general, sales or other dispositions of oil and gas
properties are accounted for as adjustments to capitalized costs, with no gain
or loss recorded. Amortization of evaluated oil and gas properties is computed
on the units of production method based on all proved reserve quantities, on a
country-by-country basis. The net capitalized costs of evaluated oil and gas
properties (full cost ceiling limitation) are not to exceed their related
estimated future net revenues discounted at 10%, and the lower of cost or
estimated fair value of unevaluated properties, net of tax considerations.
Unevaluated oil and gas properties are assessed at least annually for impairment
either individually or on an aggregate basis. Unevaluated leasehold costs,
including brokerage costs, are individually assessed based on the remaining term
of the primary leasehold. At December 31, 2001, unevaluated leasehold costs were
impaired for $1,272,836 and transferred to U.S. evaluated costs, or the full
cost pool. For the remaining costs, which includes seismic and geological and
geophysical, we estimate reserve potential for the unevaluated properties using
comparable producing areas or wells and risk that estimate by 50-75%. As
mentioned previously in Use of Estimates, reserve estimations are more imprecise
for new or unevaluated areas. Consequently, should certain geological conditions
or factors exist, such as reservoir depletion, reservoir faulting, reservoir
quality etc., but unknown to us at the time of our assessment, a materially
different result could occur.
Derivative instruments and hedging activity - We use derivatives in a
limited manner to protect against commodity price volatility. Effectively, we
sell a portion of our natural gas and crude oil based on a NYMEX based price
with a set floor (bottom) and ceiling (top) price or a range. Our derivatives
are recorded on the balance sheet at fair value and changes in the fair value of
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as part of a hedge
transaction and, if it is, depending on the type of transaction. Our derivative
contracts consist of cash flow hedge transactions in which it hedges the
variability of cash flow related to a forecasted transaction. Changes in the
fair value of these derivative instruments are recorded in other comprehensive
income and reclassified as earnings in the periods in which earnings are
impacted by the variability of the cash flows of the hedged item. The fair value
of these contracts may vary materially with the fluctuations of natural gas and
crude oil prices. However, the fluctuation in fair value will be offset by the
actual value received from the hedged volume.
26
Concentration of credit risks - Credit risk represents the accounting loss
that would be recognized at the reporting date if counter parties failed
completely to perform as contracted. Concentrations of credit risk (whether on
or off balance sheet) that arise from financial instruments exist for groups of
customers or counter parties when they have similar economic characteristics
that would cause their ability to meet contractual obligations to be similarly
affected by changes in economic or other conditions. We operate in one segment,
the oil and gas industry. A geographic concentration exists because Beta's
customers are generally located within the Central United States. Financial
instruments that subject us to credit risk consist principally of oil and gas
sales, which are based solely on short-term purchase contracts from various
customers with related accounts receivable subject to credit risk. However, we
do have certain properties, such as WEHLU, that are "captive" to one purchaser
due to the location of the production and lack of alternate sources of
purchasers. In this particular instance, Duke Energy is the purchaser.
Effects of Transactions With Related and Certain Other Parties
In March 2001, we entered into an Exploration and Development Area of
Mutual Interest Agreement in Fremont County, Wyoming with Mr. Joe C. Richardson,
Jr., one of our outside directors. We purchased from Mr. Richardson certain
geology and approximately 1,627 leased acres in a prospect located therein for
$154,800. We acquired a 75% working interest in the prospect while Mr.
Richardson retained a 25% working interest and a 5% royalty interest. All future
exploration and development costs are to be shared accordingly. At the time of
the transaction, we had projected drilling to commence on this prospect in the
last half of 2001. However, with the decline in natural gas prices in the last
half of 2001, our revised strategy for the Wind River Basin Prospect is to farm
out the initial drill site, and continue to evaluate the option acreage. In
2001, natural gas market conditions unfavorably impacted the Rocky Mountain area
with natural gas prices received in this area approximately $1.00 per Mmbtu
below the NYMEX - Henry Hub spot price. At December 31, 2001, based on the
remaining term of certain leases, we recognized an impairment of $127,229 on
this prospect and transferred that amount to the full cost pool.
In the fourth quarter of 2001, we sold approximately 6.37% in our
Matterhorn, Jackson County Texas prospect and 7.96% in our Sara White, Galveston
County, Texas prospect to Waveland Drilling Partners 2001, L.P. (Waveland
Partners). The interests were sold to Waveland Partners on standard industry
terms for both the acreage and participation in the subsequent drilling of the
prospects. We received approximately $355,989 for the acreage and received a
promote on the dry hole cost related to the drilling of these wells. Subsequent
to 2001, Waveland Drilling Partners 2002A, L.P. has acquired 8.5% in our West
Broussard, Lafayette Parish, Louisiana prospect and 10% in our Lake Boeuf,
Lafourche Parish, Louisiana prospect on similar terms. We may sell interests in
other prospects should Waveland Partners agree to our terms.
Plan of Operation for 2002
For the year 2002, we expect to fund our capital requirements from net cash
flow from operations (after general and administrative expense) and proceeds
received from the reduction or sale of our working interest in certain undrilled
projects.
We project our 2002 capital expenditure to be approximately $7 million. The
areas and amounts of concentration for the capital program will be:
o Jackson County, Texas - $1.2 million
o Red River and Lamar Counties, Texas - $.8
o Galveston County, Texas - $1.7 million
o Louisiana - $1.7 million
o Waller County, Texas - $1.0 million
o Other, including Australia - $.6 million
The allocation of the 2002 capital forecast may change materially pending
the results of the Elk Hills #1, Jackson County, Texas Wilcox test well.
27
We are projecting our cash flows from operations to be approximately $4.8
million based on an average natural gas price of $2.37 per Mcf and $18.88 per
barrel and average net daily production of 10.0 MMcfE. Estimated proceeds from
sale and reduction of our working interests in certain evaluated and unevaluated
prospects are approximately $3.4 million. As with any projection, the timing and
amounts can vary. Generally, funds must be advanced within thirty days or less
after our election to participate in the drilling of a well.
Our planned capital expenditures and/or administrative expenses could
exceed those amounts budgeted and could exceed our cash from all sources. While
our projected cash expenditures may be as projected, cash flow from operations
could be unfavorably impacted by lower than projected commodity prices and/or
lower than projected production rates. Conversely, higher than projected
commodity prices would favorably impact our projected cash flow from operations.
Additionally, lower natural gas and crude oil prices could adversely impact our
ability to receive any proceeds from the sale of our prospects. If this happens,
it may be necessary for us to raise additional funds.
We have approximately 375,725 callable common stock purchase warrants
outstanding exercisable at a price of $7.50 per share. We are able to call these
warrants at any time after our common stock has traded on Nasdaq at a market
price equal to or exceeding $10.00 per share for 10 consecutive days which was
achieved in July 2000. It is our intent to call all of these warrants at such
time, if and when, the cash is needed to fund capital requirements. We will
receive proceeds equal to the exercise price times the number of shares which
are issued from the exercise of warrants net of commission to the broker of
record, if any. We could realize net proceeds of approximately $2,814,500 from
the exercise of all of these warrants. There is no assurance that any warrants
will be exercised or that we will ever realize any proceeds from the $7.50
warrant calls. However, due to current market conditions and the current price
of our stock, it is not probable that we will call these warrants in the first
half of 2002.
We may seek mezzanine financing, if available, on terms acceptable to us.
Mezzanine financing usually involves debt with a higher cost of capital as
compared to conventional bank financing. We would seek mezzanine financing in
the range of $1,000,000 to $5,000,000. We would seek to use this means of
financing in the event that a particular acquisition did not have sufficient
proved producing reserve collateral to support a conventional bank loan.
We may realize additional cash flow from oil and gas wells to be drilled,
if found to be productive. We own working interests in wells that are currently
producing and in additional wells, which are presently being completed and
equipped for production. For 2002, we currently estimate that the wells will
generate approximately $7.5 million of net cash flow after deducting lease
operating expenses of approximately $3.0 million.
If the above additional sources of cash are insufficient or are unavailable
on terms acceptable to us, we will be compelled to reduce the scope of our
business activities. If we are unable to fund planned expenditures within a
thirty to sixty-day period after a well is proposed for drilling, it may be
necessary to:
1) Forfeit our interest in wells that are proposed to be drilled;
2) Farm-out our interest in proposed wells;
3) Sell a portion of our interest in proposed wells and use the sale
proceeds to fund our participation for a lesser interest; or
4) Reduce general and administrative expenses.
Should our future projected capital expenditures be reduced by lower
sources of cash flow or additional cash is required for reduction of our credit
facility, our potential growth rate from our exploration activity could be
materially impacted. An alternative action to maintain our growth potential
would be the acquisition of existing reserves with the use of debt and equity
instruments.
Our long-term goal is to continue the pattern of growing the Company by
accumulating oil and gas reserves through acquisition and drilling. In the event
we cannot raise additional capital, or the industry market is unfavorable, we
may have to slow or alter our long-term goal accordingly. Should we achieve our
long-term goal and an acceptable value for our shareholders is recognized over
the next two to three years, selling a portion or all of the Company is a
possibility.
28
These are forward looking statements that are based on assumptions, which in
the future may not prove to be accurate. Although we believe that the
expectations reflected in such forward looking statements are based on
reasonable assumptions, we can give no assurance that our expectations will be
achieved.
Comparison of Results of Operations Year ended December 31, 2001 and Compared
to Year ended December 31, 2000
We had a reported net loss of ($9,046,084) for the year ended December 31,
2001 compared to net income of $1,425,565 the same period ended 2000. Our
results of operations for 2001 included full-cost ceiling impairments at
September 30, 2001 of $6,770,110 ($4,879,718 net of income tax) and at December
31, 2001 of $7,034,925 ($5,070,590 net of income tax). The full-cost ceiling
impairments were a result of declining natural gas and crude oil prices in the
last half of 2001 and marginal success with our exploration program during the
year. At December 31, 2001 and at September 30, 2001, the total cost of our U.S.
evaluated properties exceeded their net realizable value, based on December 31,
2001 and September 30, 2001 prices, respectively, and accordingly non-cash write
downs were recorded as required by SEC rules. Net income, excluding the full
cost ceiling impairments, for the year 2001 was $904,224 compared to net income
of $1,425,565 for the year 2000. Higher depletion expense and operating expense
and a non-recurring charge of $205,415 relating to the settlement of a gas
contract dispute contributed to the lower net income for 2001.
The following table summarizes key items of comparison and their related
increase (decrease) for the twelve months ended December 31 for the periods
indicated.
In Thousands ................................ Years Ended December 31, $ - Increase % - Increase
2001 2000 (Decrease) (Decrease)
---------- ---------- ----------- -----------
Net income (loss) ..................... $ (9,046.1) $ 1,425.6 $(10,471.7)
Oil and gas sales ..................... 12,788.1 8,037.2 4,750.9 59%
Field service income .................. 868.4 320.6 547.8 171%
Operating expense ..................... 3,469.2 1,368.8 2,100.4 153%
Field service expense ................. 339.3 147.3 192.0 130%
G&A expense ........................... 2,679.1 2,141.0 538.1 25%
Depletion - Full cost ................. 4,858.4 2,604.3 2,254.1 87%
Depreciation - Field service and
Other ............................... 318.5 89.1 229.4 257%
Impairment expense .................... 13,805.0 -- 13,805.0 --
Interest expense ...................... 867.8 393.0 474.8 121%
Income tax - (provision)benefit. ...... (3,504.4) 294.3 (3,798.7) --
Production:
Natural Gas - Mcf ..................... 2,512.5 1,726.4 786.1 46%
Crude Oil - Bbl ....................... 114.3 32.6 81.7 251%
Natural Gas Equivalent - McfE ......... 3,198.3 1,922.1 1,276.1 66%
$ per unit:
Ave gas price - Mcf ................... $ 3.97 $ 4.08 $ (.11) (3%)
Ave oil price - Bbl ................... 24.72 30.57 (5.85) (19%)
Ave operating expense - McfE .......... 1.08 .71 .37 52%
Ave G&A - McfE ........................ .84 1.12 (.28) (25%)
Ave Depl. and Depr. - McfE ............ 1.62 1.40 .22 16%
For the year ended December 31, 2001, oil and gas sales increased
$4,750,881 or 59%, from the year ended 2000, to $12,788,115. Increased
production volume of natural gas and crude oil resulted in additional revenues
of $5,701,359 or a 71% increase in oil and gas sales for 2001 compared to 2000.
Of the increase in oil and gas sales due to higher production volume, natural
gas comprised 56% of the increase while crude oil accounted for the remaining
44%. The increase in the production volume for the year ended 2001, compared to
the same period for 2000, was due to acquired production in the Red River Energy
acquisition and new wells connected in the 2001 and the last of half of 2000.
However, lower natural gas and crude oil prices for 2001 resulted in lower
revenues of approximately $950,478, or a 12% decrease in oil and gas sales for
2001 compared to 2000. Of the decrease in oil and gas sales due to lower prices,
natural gas comprised 30% of the decrease with lower crude oil prices accounting
for the remaining 70%.
29
Generally, we sell our natural gas to various purchasers on an
indexed-based price. These indices are generally affected by the NYMEX - Henry
Hub spot price. We use hedges on a limited basis to lessen the impact of price
volatility. Hedges covered approximately 27% of our production on an equivalent
Mcf basis for the year ended December 31, 2001. Based on our natural gas
production for the twelve months ended December 31, 2001, a decline in the
average natural gas price realized by Beta of $1.00 per Mcf would have resulted
in an approximate $2.5 million reduction in net income before income taxes.
Operating expenses, including production and ad valorem taxes, increased
$2,100,406, or 153%, to $3,469,194 for the year ended December 31, 2001 compared
to the same period for 2000. The increased expenses were due to additional
operating expenses associated with the Red River Energy acquisition properties,
higher production and severance taxes from increased oil and gas sales and an
increase in number of wells put on production during 2001 and the last half of
2000. The average operating expense, including production tax, for the Red River
Energy acquisition oil and gas properties was approximately $1.39 per equivalent
Mcf for the year ended December 31, 2001. This operating cost per equivalent Mcf
is significantly higher than the 2001 average for the remaining properties of
$.58 per equivalent Mcf due to the Red River Energy acquisition properties being
older in production life and the necessity to dispose of a significant volume of
salt water produced. Additionally, due to the age of the properties, repair and
maintenance costs are higher than that of the other properties.
Field service expense relates to the operation of our McIntosh County, OK
gathering system that was acquired in the Red River Energy acquisition. The
increase in expense for 2002 was due to having the system for twelve months
versus four months in 2001.
General and administrative expenses for the twelve months ended December
31, 2001 increased approximately $538,116, or 25%, to $2,679,121 compared to
$2,141,005 for the same period in 2000. The increase was due to 1.) a
non-recurring charge of $205,415 relating to the settlement of a gas contract
dispute (for further discussion please refer to Item 3. Legal Proceedings) and
2.) increased salary and associated personnel expense related to personnel hired
in the Red River Energy acquisition and outside services, which provide
operational accounting services for the properties from the Red River Energy
acquisition, and overall increase in corporate activity for the year.
Depletion and depreciation expense increased $2,483,458, or 92%, from the
same period in 2000 to $5,176,897 for the twelve months ended December 31, 2001.
Depletion associated with evaluated oil and gas properties comprised $2,254,036,
or 91%, of this increase. Depletion for oil and gas properties is calculated
using the "Unit of Production" method, which essentially amortizes the
capitalized costs associated with the evaluated properties based on the ratio of
production volume for the current period to total remaining reserve volume for
the evaluated properties. Therefore, due to the increase in production volume
for the year ended December 31, 2001 compared to the same period ended 2000 and
increased costs for our evaluated properties due to the drilling activity during
the year, depletion expense increased. Depletion expense on a per Mcf equivalent
basis for the twelve months ended December 31, 2001 was $1.51 per Mcf compared
to $1.35 per Mcf for the same period in 2000. Depreciation expense, related to
other assets, for the twelve months ended December 31, 2001 was $318,533, or
$.09 per Mcf, compared to $89,111, or $.05 per Mcf, for the same period in 2000
or an increase of $229,422. Of the increase, $195,033 was related to gathering
assets acquired in the Red River Energy acquisition, which are depreciated
separately from the oil and gas properties. Furniture, fixtures and other
equipment comprised the remainder of the increase.
At December 31, 2001 and September 30, 2001, the total capitalized costs for
the U.S. evaluated properties full cost pool exceeded the net realizable value
of the properties and accordingly impairment write-downs of $7,034,925 and
$6,770,110, were recorded in the three-month periods ended December 31, 2001 and
September 30, 2001, respectively. The impairments were due mainly to the
significant decline in the price of natural gas and crude oil since December 31,
2000 and higher future operating expenses regarding production on the older
properties. The prices used in the determination on the net realizable at
December 31, 2001 and September 30, 2001 were $2.65 and $2.20 per Mcf,
respectively, for natural gas and $18.17 and $23.50 per barrel, respectively,
for crude oil. The prices used at December 31, 2000 for the impairment test were
$10.14 per Mcf for natural gas and $26.06 per barrel for crude oil.
30
Interest expense increased for twelve months ended December 31, 2001,
compared to the same period 2000 as a result of the debt acquired in the Red
River Energy acquisition. The increase was partially offset by lower interest
rates for 2001 compared to the rates in effect for 2000.
Year ended December 31, 2000 and Compared to Year ended December 31, 1999
We have reported net income of $1,425,565 for the year ended December 31,
2000 compared to a net loss of ($5,348,403) for the same period ended 1999. Our
results of operations have been significantly impacted by our ability to
increase production through our exploration activities and acquiring oil and gas
properties. Fluctuations in natural gas and crude oil prices have also
significantly impacted these results.
The following table summarizes key items of comparison and their related
increase (decrease) for the twelve months ended December 31 for the periods
indicated.
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 ........... 1,368.8 81.5 1,287.3 1580%
Field service expense ....... 147.3 -- 147.3 --
G&A expense 2,141.0 1,418.2 722.8 51%
Depletion - Full cost ....... 2,604.3 914.2 1,779.2 195%
Depreciation - Field service and
Other ..................... 89.1 -- 89.1 --
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 - McfE .71 0.17 0.54 318%
Ave G&A - McfE .............. 1.12 2.92 (1.80) -62%
Ave Depl. and Depr. - McfE .. 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 Red River Energy acquisition. Approximately 67% of
the increase in our natural gas production was due to new wells drilled and
completed during the twelve months ended December 31, 2000. Acquired crude oil
production accounted for approximately 88% of the increase in oil production for
the year. Higher natural gas prices for 2000 resulted in approximately
$2,800,000 in additional oil and gas revenues. Generally, we sell our natural
gas to various purchasers on an indexed-based price. These indices are generally
affected by the NYMEX - Henry Hub spot price. We use hedges on a limited basis
to lessen the impact of price volatility. However, fixed pricing from hedges
only cover 22% of our production on an equivalent Mcf basis. Based on our 2000
natural gas production, a change in the average natural gas price we realized of
$1.00 per Mcf would have resulted in an approximate $1.5 million reduction in
net income before income taxes.
Operating expenses, including production and ad valorem taxes, increased
approximately $1,287,250, or 1580%, to $1,368,788 for the year ended 2000. The
increased expenses were due to approximately $1,000,000 of additional operating
expenses associated with the Red River Energy acquisition properties, which
included a gathering system, and the increase in number of wells put on
production for the year. The average operating expense for the Red River Energy
acquisition oil and gas wells was $1.51 per equivalent Mcf for the period
September 1, 2000 through December 31, 2000. This operating cost per equivalent
Mcf is significantly higher than the average for the remaining properties of
$.33 per equivalent Mcf due to the Red River Energy acquisition properties being
older in production life and the necessity to dispose of a significant volume of
salt water produced. Additionally, due to the age of the properties, repair and
maintenance costs are higher than that of the other properties.
31
Field service expense relates to the operation of our McIntosh County, OK
gathering system which was acquired in the Red River Energy acquisition. There
was no comparable expense in 1999.
G&A expenses for the twelve months ended December 31, 2000 increased in
absolute dollars by approximately $722,800 but decreased $1.80 on a per
equivalent Mcf basis from the same period in 1999. The following shows the major
items accounting for the 2000 increase:
o Relocation and severance expense associated with our corporate office
move from Newport Beach, CA to Tulsa, OK of $289,000 which included a
non-cash charge of $128,000 associated with the vesting rights on stock
warrants of a former officer/employee
o Incremental increase in costs associated with additional employees
hired from the Red River Energy acquisition, which was approximately
$261,000 for the four-month period September 2000 through December 2000
o Fees of approximately $124,000 associated with our entry on NASDAQ's
National Market system
o Overall increase in corporate expenses of approximately $120,000 due to
increased level of activity from our growth.
Depletion and depreciation expense increased $1,779,206, or 195%, to
$2,693,439 for 2000 from $914,233 in 1999 due to increase production volume in
2000. Our average depletion and depreciation rate per equivalent Mcf for 2000
decreased 26% to $1.40 from $1.88 in 1999 primarily as a result of the reserves
acquired in the Red River Energy acquisition and those reserves discovered from
our exploration effort during the year.
There was no impairment expense for the twelve-month period ended December
31, 2000 due to the determination of the total evaluated costs in both the U.S.
and foreign cost pools exceeding their net realizable value. In 1999, it was
determined that the total costs in the U.S. evaluated properties cost pool
exceeded their present value and accordingly an impairment write-down of
$1,167,910 was recorded. The impairment was due mainly to downward revisions of
reserve estimates associated with two wells drilled in 1998. The downward
revisions were due to disappointing production results from the wells in the
fourth quarter of 1999 when producing zones in the wells commenced significant
production of salt water in place of gas and oil. Additionally, a $57,052
impairment charge was recorded for our evaluated cost associated with our
Australian properties.
Interest expense decreased for the year ended December 31, 2000 compared to
the same period for 1999 primarily due to the retirement of our bridge notes,
which were retired in July 1999. Interest expense related to the bridge notes
for 1999 consisted of the following:
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 Red River Energy acquisition.
32
Income Taxes
As of December 31, 2001, we had available, to reduce future taxable income,
a Federal net operating loss carryforward of approximately $12,657,100, which
expires in the years 2012 through 2021. Utilization of the tax net operating
loss carryforward may be limited in the event a 50% or more change of ownership
occurs within a three-year period. The tax net operating loss carryforward may
be limited by other factors as well. As of December 31, 2001 we had no deferred
taxes.
Impact of Recently Issued Standards
In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for which
the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill and requires unallocated negative goodwill to be written off
immediately as an extraordinary gain, rather than deferred and amortized. SFAS
142 changes the accounting for goodwill and other intangible assets after an
acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and
intangible assets with indefinite lives will no longer be amortized; 2) goodwill
and intangible assets with indefinite lives must be tested for impairment at
least annually; and 3) the amortization period for intangible assets with finite
lives will no longer be limited to forty years. We do not believe that the
adoption of these statements will have a material effect on our financial
position, results of operations, or cash flows.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. We will adopt the statement effective no later
than January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, we cannot reasonably estimate the effect of
the adoption of this statement on our financial position, results of operations,
or cash flows.
In October 2001, the FASB also approved SFAS 144, Accounting for the
Impairment or Disposal of Long-Lived Assets. SFAS 144 replaces SFAS 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of. The new accounting model for long-lived assets to be disposed of
by sale applies to all long-lived assets, including discontinued operations, and
replaces the provisions of APB Opinion No. 30, Reporting Results of
Operations-Reporting the Effects of Disposal of a Segment of a Business, for the
disposal of segments of a business. Statement 144 requires that those long-lived
assets be measured at the lower of carrying amount or fair value less cost to
sell, whether reported in continuing operations or in discontinued operations.
Therefore, discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred.
Statement 144 also broadens the reporting of discontinued operations to include
all components of an entity with operations that can be distinguished from the
rest of the entity and that will be eliminated from the ongoing operations of
the entity in a disposal transaction. The provisions of Statement 144 are
effective for financial statements issued for fiscal years beginning after
December 15, 2001 and, generally, are to be applied prospectively. At this time,
the Company cannot estimate the effect of this statement on its financial
position, results of operations, or cash flows.
33
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
We are exposed to market risk related to adverse changes in oil and gas
prices. Our oil and gas revenues can be significantly affected by volatile oil
and gas prices. This volatility can be mitigated through the use of oil and gas
derivative financial hedging instruments. Based on the month December 2001
production rate, we have approximately 29% of our current natural gas production
hedged for January and February 2002 increasing to approximately 53% for the
remainder of 2002 until January 2003. We have approximately 41% of crude oil
hedged through March 2003. We use costless collars to hedge our production. For
more information please refer to Item 8. Financial Statements, Note 7.
Derivative and Hedging Activities. The remainder of our production is not hedged
and we may continue to experience wide fluctuations in oil and gas revenues as a
result. We are also exposed to market risk related to adverse changes in
interest rates. This volatility could be mitigated through the use of financial
derivative instruments. Currently, we do not have any derivative financial
instruments in place to mitigate this potential risk.
Item 8. Financial Statements and Supplementary Data.
Our financial statements and supplementary financial data, which begin on
page F-1, are included elsewhere in this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
34
PART III
Item 10. Directors And Executive Officers Of The Registrant.
The information required to be contained in this Item is incorporated by
reference to our definitive proxy statement to be filed with respect to our 2002
annual meeting under the headings "Proposal One -- Election of Directors,"
"Executive Officers" and "Section 16(a) Beneficial Ownership Reporting
Compliance."
Item 11. Executive Compensation
The information required to be contained in this Item is incorporated by
reference to our definitive proxy statement to be filed with respect to our 2002
annual meeting under the heading "Executive Compensation."
Item 12. Security Ownership Of Certain Beneficial Owners And Management
The information required to be contained in this Item is incorporated by
reference to our definitive proxy statement to be filed with respect to our 2002
annual meeting under the heading "Principal Stockholders and Security Ownership
of Management."
Item 13. Certain Relationships And Related Transactions
The information required to be contained in this Item is incorporated
by reference to our definitive proxy statement to be filed with respect to our
2002 annual meeting under the heading "Certain Transactions."
35
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) The following documents are filed as part of this report:
Letter Agreement Between Avalon Exploration, Inc. and Beta Oil & Gas,
Inc. dated September 7, 2001 amending Revised Joint Development
Agreement dated August 8, 2000 between Red River Energy, L.L.C. and
Avalon Exploration, Inc.
Consent of Hein + Associates, LLP. dated March 28, 2002
Consent of Ryder Scott and Associates dated March 28, 2002
For a list of Financial Statements and Schedules, see "Index to the
Financial Statements and Schedules" on page F-1
(b) No reports on Form 8-K were filed during the fourth quarter ended
December 31, 2001:
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
3.1 Original Articles of Incorporation of Registrant incorporated by reference
to Exhibit 3.1 of Beta's S-1 Registration Statement No. 333-68381
filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/data/1059324/
001059324-98-000005.txt).
3.2 Amended and Restated Bylaws of the Registrant, Dated October 29, 1998,
incorporated by reference to Exhibit 3.2 of Beta's S-1 Registration
Statement No. 333-68381 filed December 4, 1998 at
(http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt).
3.3 Certificate of Amendment of Articles of Incorporation of the Registrant,
dated August 28, 2000, incorporated by reference to Exhibit 3.1 of Beta's
S-1 Registration Statement No. 333-68381 filed December 4, 1998 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt)
10.1 Formosa Grande Prospect Agreement, Dated August 1, 1997, incorporated by
reference to Exhibit 10.1 of Beta's S-1 Registration Statement No. 333-
68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/data/
1059324/0001059324-98-000005.txt).
10.2 Texana Prospect Agreement, Dated July 15, 1997, incorporated by reference
to Exhibit 10.2 of Beta's S-1 Registration Statement No. 333-68381 filed
December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/
1059324/0001059324-98-000005.txt).
10.3 Ganado Prospect Agreement, Dated November 1, 1997, incorporated by
reference to Exhibit 10.3 of Beta's S-1 Registration Statement No.
333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/
data/ 1059324/0001059324-98-000005.txt).
10.4 T.A.C. Resources Agreement, Dated January 21, 1998, incorporated by
reference to Exhibit 10.4 of Beta's S-1 Registration Statement No.
333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/
data/ 1059324/0001059324-98-000005.txt).
10.5 Lapeyrouse Prospect Agreement, Dated October 13, 1997, incorporated by
reference to Exhibit 10.5 of Beta's S-1 Registration Statement No.
333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/
data/ 1059324/0001059324-98-000005.txt).
10.6 Rozel (Transition Zone) Prospect Agreement, Dated February 24,1998,
incorporated by reference to Exhibit 10.6 of Beta's S-1 Registration
Statement No. 333-68381 filed December 4, 1998 at (http://www.sec.gov/
Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.7 Stansbury Basin (Australia) Prospect Agreement, Dated February 1998,
incorporated by reference to Exhibit 10.7 of Beta's S-1 Registration
Statement No. 333-68381 filed December 4, 1998 at (http://www.sec.gov/
Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.9 Steve Antry Employment Agreement, Dated June 23,1997, incorporated by
reference to Exhibit 10.9 of Beta's S-1 Registration Statement No. 333-
68381 filed December 4, 1998 at(http://www.sec.gov/Archives/
edgar/ data/1059324/0001059324-98-000005.txt)
36
10.14BWC Prospect Agreement, Dated April 1, 1998, incorporated by reference to
Exhibit 10.14 of Beta's S-1 Registration Statement No. 333-68381 filed
December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/
1059324/0001059324-98-000005.txt).
10.19Redfish Prospect Agreement Dated January 6, 1999, incorporated by
reference to Exhibit 10.19 of Beta's Amendment No. 2 to S-1/A Registration
Statement No. 333-68381 filed May 3, 1999 at (http://www.sec gov/
Archives/edgar/data/1059324/0001059324-99-000011.txt).
10.20 Shark Prospect Agreement Dated January 6, 1999, incorporated by reference
to Exhibit 10.20 of Beta's Amendment No. 2 to S-1/A Registration
Statement No. 333-68381 filed May 3, 1999 at (http://www.sec.gov/Archives
/edgar/data/1059324/0001059324-99-000011.txt).
10.21 Cheniere Energy, Inc. Option Agreement Dated January 6, 1999,
incorporated by reference to Exhibit 10.21 of Beta's Amendment No. 2 to
S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at
(http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.22 Dyad-Australia, Inc. Agreement Dated January 25, 1999, incorporated by
reference to Exhibit 10.22 of Beta's Amendment No. 2 to S-1/A
Registration Statement No. 333-68381 filed May 3, 1999 at
(http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.24Northeast Hitchcock Agreement Dated July 30, 1999, incorporated by
reference to Exhibit 10.24 of Beta's Form 10-K/A for the year 1999
filed March 30, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/
0001059324-00-000007.txt)
10.25Sarah White Agreement Dated July 30, 1999, incorporated by reference to
Exhibit 10.25 of Beta's Form 10-K/A for the year 1999 filed March 30,2000
at http://www.sec.gov/Archives/edgar/data/1059324/0001059324-00-000007.txt)
10.27 Revised Joint Development Agreement dated August 8, 2000 between Red
River Energy, L.L.C. and Avalon Exploration, Inc., incorporated by
reference to Exhibit 10.27 of Beta's Third Quarter Form 10-Q filed
November 14, 2000 at ( http://www.sec.gov/Archives/edgar/ data/1059324/
000105932400000042/0001059324-00-000052.txt).
10.29Mushroom Project Participation Agreement, Austin and Waller Counties,
Texas, dated June 14, 2000, incorporated by reference to Exhibit 10.29 of
Beta's Form 10-K for the year 2000 filed April 2, 2001 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt).
10.30Starboard Area Letter Agreement, Terrebone Parish, Louisiana dated June
16, 2000 incorporated by reference to Exhibit 10.30 of Beta's Form
10-K for the year 2000 filed April 2, 2001 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt).
10.31First Amended and Restated Revolving Credit Agreement between Bank of
Oklahoma and Red River Energy, LLC dated March 30, 1999, incorporated by
reference to Exhibit 10.31 of Beta's Form 10-K for the year 2000 filed
April 2, 2001 at (http://www.sec.gov/Archives/edgar/data/
1059324/000102189001500087/ 0001021890-01-500087.txt).
10.32First Amendment to First Amended and Restated Revolving Credit Agreement
between Bank of Oklahoma and Red River Energy, LLC dated February 1, 2000,
incorporated by reference to Exhibit 10.32 of Beta's Form 10-K for the
year 2000 filed April 2, 2001 at (http://www.sec.gov/Archives/edgar/data/
1059324/000102189001500087/0001021890-01-500087.txt).
10.33Second Amendment to First Amended and Restated Revolving Credit Agreement
between Bank of Oklahoma and Red River Energy, LLC dated June 15, 2000,
incorporated by reference to Exhibit 10.33 of Beta's Form 10-K for the
year 2000 filed April 2, 2001 at (http://www.sec.gov/Archives/edgar/
data/1059324/000102189001500087/0001021890-01-500087.txt).
10.34Third Amendment to First Amended and Restated Revolving Credit Agreement
between Bank of Oklahoma and Beta Oil & Gas, Inc. dated March 19,
2001, incorporated by reference to Exhibit 10.34 of Beta's Form 10-K
for the year 2000 filed April 2, 2001at (http://www.sec.gov/Archives/edgar/
data/1059324/000102189001500087/0001021890-01-500087.txt).
10.35Form of Placement Agent Agreement for Preferred Placement Offering dated
March 15, 2001, incorporated by reference to Exhibit 10.35 of Beta's Form
10-K for the year 2000 filed April 2, 2001 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt).
10.36 Letter Agreement Between Avalon Exploration, Inc. and Beta Oil & Gas,
Inc. dated September 7,2001 amending Revised Joint Development Agreement
dated August 8, 2000 between Red River Energy, L.L.C. and Avalon
Exploration, Inc., incorporated by reference to Exhibit 10.27 of Beta's
Third Quarter Form 10-Q filed November 14, 2000.
21 List of Subsidiaries incorporated by reference to Exhibit 21 of Beta's
Form 10-K for the year 2000 filed April 2, 2001 at (http://www.sec.gov/
Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
23.2 Consent of Hein + Associates, LLP. dated March 28, 2002
23.3 Consent of Ryder Scott and Associates dated March 28, 2002
99 The Amended 1999 Incentive and Nonstatutory Stock Option Plan, incorporated
by reference to Exhibit 99 of Beta's 14A Definitive Proxy Statement
dated and filed August 14, 2000 at (http://www.sec.gov/Archives
/edgar/data/1059324/000105932400000042/0001059324-00-000042-0001.htm).
37
Beta Oil & Gas, Inc.
and Subsidiaries
Consolidated Financial Statements
For the Years Ended
December 31, 2001, 2000 and 1999
INDEX TO FINANCIAL STATEMENTS
Page
Independent Auditor's Report..........................................F-2
Consolidated Balance Sheets - December 31, 2001 and 2000..............F-3
Consolidated Statements of Operations - For the Years Ended
December 31, 2001, 2000 and 1999...............................F-4
Consolidated Statement of Stockholders' Equity - For the Years Ended
December 31, 2001, 2000 and 1999.................................F-5
Consolidated Statements of Cash Flows - For the Years Ended
December 31, 2001, 2000 and 1999...............................F-7
Notes to Consolidated Financial Statements............................F-9
F-1
INDEPENDENT AUDITOR'S REPORT
The Stockholders and Board of Directors
Beta Oil & Gas, Inc.
Tulsa, Oklahoma
We have audited the consolidated balance sheets of Beta Oil & Gas, Inc.
and subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of operations, stockholders' equity, and cash flows for the
three years in the period ended December 31, 2001. These financial statements
are the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Beta Oil &
Gas, Inc. and subsidiaries as of December 31, 2001 and 2000 and the results of
their operations and their cash flows for the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.
/s/HEIN + ASSOCIATES LLP
HEIN + ASSOCIATES LLP
Certified Public Accountants
Orange, California
February 15, 2002
F-2
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, DECEMBER 31,
2001 2000
------------------- -------------------
CURRENT ASSETS:
Cash $ 556,199 $ 1,536,186
Accounts receivable
Oil and gas sales 1,397,532 2,766,405
Other 754,390 95,439
Income tax receivable 38,503 -
Futures transaction hedge asset 68,508 -
Prepaid expenses 187,495 200,615
---------------- ----------------
Total current assets 3,002,627 4,598,645
OIL AND GAS PROPERTIES, at cost (full cost method)
Evaluated properties 58,708,444 44,398,497
Unevaluated properties 13,001,443 13,450,347
Less - accumulated amortization and impairment of full cost pool (25,058,725) (6,395,326)
----------------- ----------------
Net oil and gas properties 46,651,162 51,453,518
OTHER OPERATING PROPERTY AND EQUIPMENT, at cost
Gas gathering system 1,491,516 1,454,212
Support equipment 221,413 217,462
Other 198,520 114,672
Less - accumulated depreciation (408,430) (118,497)
----------------- -----------------
Net other operating property and equipment 1,503,019 1,667,849
OTHER ASSETS 1,472,570 746,140
---------------- ----------------
TOTAL ASSETS $ 52,629,378 $ 58,466,152
================ ================
CURRENT LIABILITIES:
Current portion of long-term debt $ 57,407 $ 89,209
Accounts payable, trade 2,472,203 629,696
Income taxes payable - 198,650
Dividends payable 112,708 -
Other accrued liabilities 463,859 147,853
---------------- ----------------
Total current liabilities 3,106,177 1,065,408
LONG-TERM DEBT, less current portion 13,648,727 13,814,034
DEFERRED INCOME TAXES - 3,526,304
COMMITMENTS AND CONTINGENCIES (Notes 4, 6 and 10)
STOCKHOLDERS' EQUITY
Preferred stock, $.001 par value, 5,000,000 shares authorized; 604,272 and
0 issued and outstanding at December 31, 2001 and 2000, respectively.
Liquidation value at December 31, 2001 is $5,923,834 604 -
Common stock, $.001 par value; 50,000,000 shares authorized; 12,398,572 and
12,340,951 shares issued and 12,356,072 and 12,340,951 outstanding at
December 31, 2001 and 2000, respectively 12,399 12,341
Additional paid-in capital 51,814,699 46,592,976
Treasury stock, at cost; 42,500 shares reacquired at December 31, 2001 (198,920) -
Accumulated other comprehensive income 68,508 -
Accumulated deficit (15,822,816) (6,544,911)
----------------- -----------------
Total stockholders' equity 35,874,474 40,060,406
---------------- ----------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 52,629,378 $ 58,466,152
================ ================
See accompanying notes to consolidated financial statements.
F-3
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
FOR THE YEARS ENDED DECEMBER 31,
2001 2000 1999
------------------- ------------------ ------------------
REVENUES:
Oil and gas sales $ 12,788,115 $ 8,037,234 $ 1,199,480
Field services 868,406 320,633 -
---------------- ---------------- ----------------
Total revenue 13,656,521 8,357,867 1,199,480
-------------- ---------------- ----------------
COSTS AND EXPENSES:
Lease operating expense 3,469,194 1,368,788 81,538
Field services 339,329 147,325 -
General and administrative 2,679,121 2,141,005 1,418,240
Full cost ceiling impairment 13,805,035 - 1,224,962
Depreciation and amortization expense 5,176,897 2,693,439 914,233
------------- ---------------- ----------------
Total costs and expenses 25,469,576 6,350,557 3,638,973
------------- ---------------- ----------------
INCOME (LOSS) FROM OPERATIONS (11,813,055) 2,007,310 (2,439,493)
-------------- ---------------- -----------------
OTHER INCOME (EXPENSE):
Interest expense (867,835) (393,008) (2,966,651)
Interest income and other 130,374 105,563 21,741
-------------- ---------------- ----------------
Total other income (expense) (737,461) (287,445) (2,944,910)
--------------- ----------------- -----------------
INCOME (LOSS) BEFORE TAX PROVISION (12,550,516) 1,719,865 (5,384,403)
INCOME TAX BENEFIT (PROVISION) 3,504,432 (294,300) -
--------------- ----------------- -----------------
NET INCOME (LOSS) (9,046,084) 1,425,565 (5,384,403)
PREFERRED DIVIDENDS (231,821) - -
----------------- ---------------- -----------------
NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDER
$ (9,277,905) $ 1,425,565 $ (5,384,403)
=============== ================ =================
BASIC NET INCOME (LOSS) PER COMMON SHARE $ (.75) $ 0.13 $ (0.66)
=============== ================ =================
DILUTED NET INCOME (LOSS) PER COMMON SHARE $ (.75) $ 0.13 $ (0.66)
=============== ================ =================
COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS) $ (9,046,084) $ 1,425,565 $ (5,384,403)
OTHER COMPREHENSIVE INCOME:
Transition adjustment related to change in
accounting for derivative instruments and
hedging activities (net of income taxes) (953,488) - -
Reclassification of realized loss on
qualifying cash flow hedges (net of income taxes) 340,048 - -
Unrealized gain on qualifying cash
flow hedges (net of income taxes) 681,948 - -
---------------- ---------------- -----------------
TOTAL COMPREHENSIVE INCOME (LOSS) $ (8,977,576) $ 1,425,565 $ (5,384,403)
=============== ================ =================
F-4
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS'EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
ACCUM.
ADDITIONAL OTHER TOTAL
PREFERRED COMMON PAID-IN TREASURY COMP. ACCUM. STKHLDRS'
SHARES .. AMOUNT SHARES AMOUNT CAPITAL STOCK INCOME DEFICIT EQUITY
-------- -------- --------- ---------- ---------- -------- ---------- ----------- ----------
BALANCES, January 1, 1999 ..... -- $ -- 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
(Continued)
F-5
BETA OIL & GAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
(CONTINUED)
ACCUM.
ADDITIONAL OTHER TOTAL
PREFERRED COMMON PAID-IN TREASURY COMP. ACCUM. STKHLDRS'
SHARES .. AMOUNT SHARES AMOUNT CAPITAL STOCK INCOME DEFICIT EQUITY
-------- -------- --------- ---------- ---------- -------- ---------- ----------- ----------
Issuance of shares pursuant
to private placement, net 604,272 $ 604 -- $ -- $5,040,924 $ -- $ -- $ -- $5,041,528
Issuance of shares for
warrant exercise ......... -- -- 57,621 58 180,799 -- -- -- 180,857
Treasury stock acquired ....... -- -- -- -- -- (198,920) -- -- (198,920)
Preferred dividends ........... -- -- -- -- -- -- -- (231,821) (231,821)
Transition adjustment
related to change in
accounting for derivative
instruments and hedging .. -- -- -- -- -- -- (953,488) -- --
activities (net of income
taxes)
Reclassification of realized
(gain) loss on qualifying
cash flow hedges (net of
income taxes) ............ -- -- -- -- -- -- 340,048 -- --
Unrealized gain (loss) on
qualifying cash flow
hedges (net of income .... -- -- -- -- -- -- 681,948 -- 68,508
taxes)
Net loss ...................... -- -- -- -- -- -- -- (9,046,084)(9,046,084)
-------- ------ ---------- ---------- ------------ ----------- -------- ----------- -----------
BALANCES, Dec. 31, 2001 ....... 604,272 $ 604 12,398,572 $ 12,399 $51,814,699 $(198,920) $ 68,508 $(15,822,816)$35,874,474
======== ====== ========== ========== ============ =========== ======== ============ ==========
See accompanying notes to consolidated financial statements.
F-6
BETA OIL & GAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
2001 2000 1999
---------------- --------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (9,046,084) $ 1,425,565 (5,384,403)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation and amortization 5,176,897 2,693,439 914,233
Gain (loss)on sale of equipment 6,865 (2,915) -
Amortization of notes payable discount and debt
issuance costs - - 2,754,000
Impairment expense 13,805,035 - 1,224,962
Deferred income tax (3,526,304) - -
Warrants issued to consultants - 128,338 126,890
Salary contributed to Beta - - 10,000
Change in operating assets and liabilities:
Accounts receivable 709,922 (1,140,077) (736,993)
Income tax receivable (38,503) - -
Prepaid expenses 13,120 (45,109) (89,290)
Accounts payable, trade 1,828,791 535 (85,596)
Income taxes payable (198,650) 198,650 -
Other accrued expenses 316,006 (29,345) 3,542
---------------- --------------- ---------------
Net cash provided by (used in) operating activities 9,047,095 3,229,081 (1,262,655)
---------------- --------------- ---------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas property expenditures (14,927,031) (6,666,327) (6,945,695)
Proceeds received from sale of oil and
gas properties 1,065,989 - -
Gas gathering and equipment expenditures (177,103) (92,203) (1,947)
Cash acquired in merger - 895,097 -
Proceeds received from equipment sale 16,535 100,000 -
Change in other assets (726,430) (278,287) (299,051)
---------------- --------------- ---------------
Net cash used in investing activities (14,748,040) (6,041,720) (7,246,693)
---------------- --------------- ---------------
(Continued)
F-7
BETA OIL & GAS INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Continued)
FOR THE YEARS ENDED DECEMBER 31,
2001 2000 1999
------------------- ------------------- -------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock, net - - 7,733,553
Proceeds from exercise of warrants and options 180,857 3,205,139 2,052,620
Proceeds from premiums payable 152,680 51,409 71,527
Repayment of premiums payable (174,284) (27,737) (15,364)
Proceeds from bridge notes payable - - 2,894,100
Repayment of bridge notes - - (3,000,000)
Proceeds from notes payable 900,000 295,376 -
Repayment of notes payable (1,061,789) (624,017) -
Proceeds from preferred stock private placement 5,589,390 - -
Offering costs for preferred stock private placement
(547,862) - -
Acquisition of treasury stock (198,920) - -
Dividends paid (119,114) - -
Increase in deferred offering costs - - 23,524
--------------- ---------------- ----------------
Net cash provided by financing activities 4,720,958 2,900,170 9,759,960
--------------- ---------------- ----------------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (979,987) 87,531 1,250,612
CASH AND CASH EQUIVALENTS, at beginning of period
1,536,186 1,448,655 198,043
--------------- ---------------- ----------------
CASH AND CASH EQUIVALENTS, at end of period $ 556,199 $ 1,536,186 $ 1,448,655
=============== ================ ================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION
Cash paid for:
Interest $ 867,835 $ 393,009 $ 123,552
=============== ================ ================
Income taxes $ 236,000 $ 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
Common stock and warrants issued in
settlement of debt - $ 312,280 $ -
See accompanying notes to consoidated financial statements.
F-8
BETA OIL & GAS INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Consolidation - Beta Oil and Gas, Inc. is engaged in the business of acquiring,
exploring and developing oil and gas properties. All of the Company's operating
income is derived from core areas located in Texas, Oklahoma, Kansas and
Louisiana. The Company, through one of its wholly owned subsidiaries owns a 25%
interest in an undeveloped concession located in Western Queensland, Australia.
The accompanying consolidated financial statements include the accounts of Beta
Oil & Gas, Inc. and its wholly owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated in consolidation.
Use of Estimates - The preparation of the Company's consolidated financial
statements in conformity with generally accepted accounting principles requires
the Company's management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities, if any, at the date of the financial statements, and the
reported amounts of revenues and expenses during the reporting period. The
estimates include oil and gas reserve quantities which form the basis for the
calculation of amortization and impairment of oil and gas properties. Management
emphasizes that reserve estimates are inherently imprecise and that estimates of
more recent discoveries are more imprecise than those for properties with long
production histories. Actual results could materially differ from these
estimates.
Oil and Gas Properties - The Company accounts for its oil and gas producing
activities using the full cost method of accounting as prescribed by the United
States Securities and Exchange Commission ("SEC"). Accordingly, all costs
incurred in the acquisition, exploration, and development of proved oil and gas
properties, including the costs of abandoned properties, dry holes, geophysical
costs, and annual lease rentals are capitalized. All general corporate costs are
expensed as incurred. In general, sales or other dispositions of oil and gas
properties are accounted for as adjustments to capitalized costs, with no gain
or loss recorded. Amortization of evaluated oil and gas properties is computed
on the units of production method based on all proved reserves on a
country-by-country basis. Unevaluated oil and gas properties are assessed at
least annually for impairment either individually or on an aggregate basis. The
net capitalized costs of evaluated oil and gas properties are subject to a full
cost ceiling limitation- in which the costs are not allowed to exceed their
related estimated future net revenues discounted at 10%, and the lower of cost
or estimated fair value of unproved properties, net of tax considerations.
Joint Ventures - All exploration and production activities are conducted jointly
with others and, accordingly, the accounts reflect only the Companys
proportionate interest in such activities.
Revenue Recognition - The Company recognizes oil and gas sales upon delivery to
the purchaser. Under the sales method, the Company and other joint owners may
sell more or less than their entitled share of the natural gas volume produced.
Should the Company's excess sales of natural gas exceed its share of estimated
remaining recoverable reserves a liability is recorded and revenue is deferred.
Other Operating Property and Equipment - Other operating property and equipment
are stated at cost. Provision for depreciation and amortization on property and
equipment is calculated using the straight-line and accelerated methods over the
estimated useful lives (ranging from 3 to 5 years) of the respective assets.
Amortization from the gathering assets is computed on a units of revenue method
based on the total future gross revenues. The cost of normal maintenance and
repairs is charged to operating expense as incurred. Material expenditures,
which increase the life of an asset, are capitalized and depreciated over the
estimated remaining useful life of the asset. The cost of properties sold, or
otherwise disposed of, and the related accumulated depreciation or amortization
are removed from the accounts, and any gain or losses are reflected in current
operations.
F-9
Impairment of Long-Lived Assets - In the event that facts and circumstances
indicate that the costs of long-lived assets, other than oil and gas properties,
may be impaired, an evaluation of recoverability would be performed. If an
evaluation is required, the estimated future undiscounted cash flows associated
with the asset would be compared to the asset's carrying amount to determine if
a write-down to market value or discounted cash flow value is required.
Impairment of oil and gas properties is evaluated subject to the full cost
ceiling as described under oil and gas properties.
Income Taxes - The Company accounts for income taxes using the asset and
liability method wherein deferred tax assets and liabilities are recognized for
the future tax consequences attributable to differences between financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
temporary differences are expected to be recovered or settled.
Concentrations of Credit Risk - Credit risk represents the accounting loss that
would be recognized at the reporting date if counterparties failed completely to
perform as contracted. Concentrations of credit risk (whether on or off balance
sheet) that arise from financial instruments exist for groups of customers or
counter parties when they have similar economic characteristics that would cause
their ability to meet contractual obligations to be similarly affected by
changes in economic or other conditions described below.
The Company operates in one segment, the oil and gas industry. A geographic
concentration exists because the Company's customers are generally located
within the Central United States. Financial instruments that subject the Company
to credit risk consist principally of oil and gas sales which are based solely
on short-term purchase contracts from various customers with related accounts
receivable subject to credit risk.
The table below shows the purchasers that each accounted for 10% or more of the
Company's revenue during the specified years.
2001 2000
----------------- -----------------
IP Petroleum (Pure) 8% 31%
Duke Energy 29% 19%
Cokinos Energy 5% 13%
Allegro Investments 16% 12%
We do not believe the loss of any one of our purchasers would materially affect
our ability to sell the oil and gas we produce. Other purchasers are available
in our areas of operations. We had no direct sales contracts or derivatives with
the Enron Corporation ("Enron"). Genesis Crude Oil, LP, a purchaser of our crude
oil for the Brookshire Dome area, did re-sell one month (November 2001) of crude
oil production to a subsidiary of Enron. However, at this time we have received
payment from Genesis for that month and are not aware of any adverse effect on
Genesis. We cannot guarantee that through the re-sale process there may be other
situations similar to the one previously discussed but we are not aware of any
additional dealings with Enron at this date.
Fair Value of Financial Instruments - The estimated fair values for financial
instruments under FASB Statement No. 107, Disclosures about Fair Value of
Financial Instruments, are determined at discrete points in time based on
relevant market information. These estimates involve uncertainties and cannot be
determined with precision. The estimated fair value of cash, cash equivalents,
account receivable and accounts payable approximates their carry value due to
their short-term nature. The estimated fair value of long-term debt approximates
its carrying value because the debt carries interest rates which approximate
market rates.
Stock Based Compensation - The Company has elected to follow Accounting
Principles Board Opinion No. 25, Accounting for Stock Issued to Employees
(APB25) and related interpretations in accounting for its employee stock
options. However, as required by FASB Statement No. 123 Accounting for
Stock-Based Compensation (FASB123), the Company will disclose on a proforma
basis the impact of the fair value accounting for employee stock options.
Transactions in equity instruments with non-employees for goods or services have
been accounted for using the fair value method as prescribed by
FASB123.
F-10
Derivative and Hedging Activities - In June 1998, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standards No.
133 (SFAS No.133), "Accounting for Derivative Instruments and Hedging
Activities." The FASB has subsequently issued Statements No. 137 and Statement
No. 138 which are amendments to SFAS No. 133. SFAS No. 133, as amended, is
effective for fiscal years beginning after June 15, 2000 and cannot be applied
retroactively. The Company adopted SFAS No. 133, as amended, beginning January
1, 2001.
SFAS No. 133 establishes accounting and reporting standards for derivative
instruments and for hedging activities. All derivatives will be recorded on the
balance sheet at fair value and changes in the fair value of derivatives are
recorded each period in current earnings or other comprehensive income,
depending on whether a derivative is designated as part of a hedge transaction
and, if it is, depending on the type of transaction. The Company's
derivative contract consists of a cash flow hedge transaction in which it hedges
the variability of cash flow related to a forecasted transaction. Changes in the
fair value of these derivative instruments will be recorded in other
comprehensive income and will be reclassified as earnings in the periods in
which earnings are impacted by the variability of the cash flows of the hedged
item. The ineffective portion related to basis changes and time value of all
hedges will be recognized in current period earnings.
Earnings Per Share - Basic EPS is calculated by dividing the income or loss
available to common shareholders by the weighted average number of shares
outstanding for the period. Diluted EPS reflects the potential dilution that
could occur if securities or other contracts to issue common stock were
exercised or converted into common stock.
Statement of Cash Flows - For purposes of the statement of cash flows, the
Company considers all highly liquid debt instruments purchased with an original
maturity of three months or less to be cash equivalents.
New Accounting Pronouncements - In June 2001, the Financial Accounting Standards
Board ("FASB") issued Statements of Financial Accounting Standards No. 141
"Business Combinations" ("SFAS 141") and No. 142 "Goodwill and Other Intangible
Assets" ("SFAS 142"). SFAS 141 requires all business combinations initiated
after June 30, 2001 to be accounted for under the purchase method. For all
business combinations for which the date of acquisition is after June 30, 2001,
SFAS 141 also establishes specific criteria for the recognition of intangible
assets separately from goodwill and requires unallocated negative goodwill to be
written off immediately as an extraordinary gain, rather than deferred and
amortized. SFAS 142 changes the accounting for goodwill and other intangible
assets after an acquisition. The most significant changes made by SFAS 142 are:
1) goodwill and intangible assets with indefinite lives will no longer be
amortized; 2) goodwill and intangible assets with indefinite lives must be
tested for impairment at least annually; and 3) the amortization period for
intangible assets with finite lives will no longer be limited to forty years.
The Company does not believe that the adoption of these statements will have a
material effect on its financial position, results of operations, or cash
flows.
In June 2001, the FASB also approved for issuance SFAS 143 "Asset Retirement
Obligations." SFAS 143 establishes accounting requirements for retirement
obligations associated with tangible long-lived assets, including (1) the timing
of the liability recognition, (2) initial measurement of the liability, (3)
allocation of asset retirement cost to expense, (4) subsequent measurement of
the liability and (5) financial statement disclosures. SFAS 143 requires that an
asset retirement cost should be capitalized as part of the cost of the related
long-lived asset and subsequently allocated to expense using a systematic and
rational method. The Company will adopt the statement effective no later than
January 1, 2003, as required. The transition adjustment resulting from the
adoption of SFAS 143 will be reported as a cumulative effect of a change in
accounting principle. At this time, the Company cannot reasonably estimate the
effect of the adoption of this statement on its financial position, results of
operations, or cash flows.
F-11
In October 2001, the FASB also approved SFAS 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS 144 replaces SFAS 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of. The
new accounting model for long-lived assets to be disposed of by sale applies to
all long-lived assets, including discontinued operations, and replaces the
provisions of APB Opinion No. 30, Reporting Results of Operations-Reporting the
Effects of Disposal of a Segment of a Business, for the disposal of segments of
a business. Statement 144 requires that those long-lived assets be measured at
the lower of carrying amount or fair value less cost to sell, whether reported
in continuing operations or in discontinued operations. Therefore, discontinued
operations will no longer be measured at net realizable value or include amounts
for operating losses that have not yet occurred. Statement 144 also broadens the
reporting of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. The provisions of Statement 144 are effective for financial
statements issued for fiscal years beginning after December 15, 2001 and,
generally, are to be applied prospectively. At this time, the Company cannot
estimate the effect of this statement on its financial position, results of
operations, or cash flows.
2. ACQUISITIONS AND DISPOSITIONS OF OIL AND GAS OPERATIONS:
Acquisitions - On August 30, 2000, the Company closed the previously reported
Agreement and Plan of Merger ("Agreement") to acquire 100% interest in Red River
Energy, Inc. ("RRE")(now Beta Operating Company, L.L.C.). The acquisition was
consummated through a merger ("Merger") between Beta Acquisition Company, Inc.,
a wholly owned subsidiary of the Company, and RRE following approval of the
Agreement. The effective date of the Merger was September 1, 2000.
The acquisition, recorded under the purchase method of accounting, included the
acquisition of the net assets of RRE with a value calculated to be $14,355,000
assuming an average Beta common stock price of $6.38 per share with 2,250,000
shares issued to the stockholders of RRE. The purchase price has been allocated
to assets acquired and liabilities assumed of RRE based on their estimated fair
values, which approximated book values, except for evaluated oil and gas
properties which were increased by $13,459,903 to their estimated fair value
which was determined based on a September 1, 1999 independent reserve report.
This amount has been included in the full cost amortization base of the Company.
The actual results of operations from RRE have been included in the accompanying
financial statements since the effective date of the Merger, September 1,
2000.
On September 19, 2000, the Company issued 10,000 shares of common stock, granted
100,000 callable common stock purchase warrants and gave a cash payment of
approximately $560,000 to Duke Field Services, L.L.C. ("Duke") in consideration
for the purchase of Duke's interest in the TCM coal bed properties and a note
payable due Duke with a principal balance, including interest, of $2,270,000.
The callable common stock purchase warrants were valued, as calculated under the
Black Scholes valuation model with a volatility of 53.9%, risk free interest
rate of 6.11% and an estimated time to expire of three years, at $226,030. The
warrants vest immediately, expire on September 19, 2004 and have an exercise
price of $10.78. The gain on extinguishment of debt of approximately $1,395,000
was applied against the fair value of the TCM coal bed properties as a purchase
price allocation as the coal bed properties were acquired by Beta through the
merger with RRE as described herein.
F-12
In June 2001, the Company sold its 40% working interests in certain oil and gas
properties, which represented less than 1% of the Company's proved reserves, for
$710,000. The properties were located in Pecos County, Texas.
In June 2001, the Company purchased additional working interests in certain oil
and gas properties located in the Brookshire Dome area, Waller County Texas, in
which it had existing working interests, for approximately $726,600. However,
certain existing working interest owners in these properties exercised their
preferential right to purchase their pro-rata share of the interests originally
purchased by the Company. Upon the exercise of this right in August 2001, the
Company was reimbursed by the other owners approximately $454,100 of its
original acquisition cost. The Company's net acquisition cost, after
reimbursement, was approximately $272,500 for an approximate 11.71% working
interest. The proved reserves associated with this acquisition were less than 1%
of the Company's total proved reserves.
In August 2001, the Company acquired an additional 15% working interest in its
Brookshire Dome, Waller County, Texas leasehold acreage and producing properties
for approximately $580,000. After the effect of the acquisition, the Company's
total working interest in this prospect is approximately 40%, subject to a 10%
"back-in" interest which reverts to the seller after the project payout, as
defined in the purchase and sale agreement.
In December 2001, the Company sold a portion of its interests in two unevaluated
properties, located in Jackson County and Galveston County, Texas, for $356,000.
The Company retained an approximate 16% interest in its Matterhorn, Jackson
County prospect and an approximate 34% interest in its Sara White, Galveston
County prospect. Both prospects were drilling at December 31, 2001 and are
currently in the completion stage.
Oil and gas properties - The capitalized costs at year-end and costs incurred in
oil and gas producing activities during the years were as follows:
United States Foreign Total
------------------ --------------- ----------------
2001 Capitalized costs:
Evaluated properties $ 57,027,523 $ 1,680,921 $ 58,708,444
Unevaluated properties 12,872,623 128,820 13,001,443
------------------ --------------- ----------------
69,900,146 1,809,741 71,709,887
Accumulated depreciation, depletion,
amortization and impairment (1) (23,377,455) (1,681,270) (25,058,725)
------------------ --------------- ----------------
Net capitalized costs $ 46,522,691 $ 128,471 $ 46,651,162
================== =============== ================
Cost incurred:
Property acquisition (2) $ 1,233,543 $ - $ 1,233,543
Exploration (3) 10,958,163 5,250 10,963,413
Development 1,664,086 - 1,664,086
------------------ --------------- -----------------
Total costs incurred $ 13,855,792 $ 5,250 $ 13,861,042
================== =============== ================
2000 Capitalized costs:
Evaluated properties $ 42,717,576 $ 1,680,921 $ 44,398,497
Unevaluated properties 13,326,778 123,569 13,450,347
------------------ ---------------- ----------------
56,044,354 1,804,490 57,848,844
Accumulated depreciation, depletion,
amortization and impairment (4,714,056) (1,681,270) (6,395,326)
------------------ ---------------- ----------------
Net capitalized costs $ 51,330,298 $ 123,220 $ 51,453,518
================== ================ ================
Cost incurred:
Property acquisition (4) $ 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
================== ================ ================
F-13
United States Foreign Total
---------------- ---------------- ----------------
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 (5) (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
================ ================ ================
At September 30, 2001 and December 31, 2001, the total costs in U.S. evaluated
properties exceeded their net realizable values and accordingly write downs were
recorded for $6,770,110 and $7,034,925, respectively.
(2) Net of $710,000 related to sale of evaluated oil and gas properties.
(3) Net of $355,989 related to sale of unevaluated oil and gas properties.
(4) Includes $24,845,227 related to the properties acquired in the Merger
and $3,526,304 related basis from deferred taxes.
(5) At December 31, 1999, the total costs in U.S. and foreign evaluated
properties exceeded their net realizable values and accordingly an
impairment write down of $1,224,962 was recorded.
Evaluated oil and gas properties
United States - During the year ended December 31, 2001, the Company
participated in the drilling of 51 wells, of which 49 were evaluated and the
property acquisition and exploration costs associated with the wells were
transferred to evaluated properties. Amortization expense was $4,858,364 or
$1.51 per Mcf for equivalent units of gas produced. Crude oil is converted to
equivalent units of gas on the basis of one barrel of oil to six equivalent Mcfs
of gas.
At December 31, 2001, the Company recorded an additional non-cash impairment
charge on its U.S. domestic evaluated properties of $7,034,925 due to a
significant decline in the estimated present value of future net cash flows from
these properties due to lower pricing and increased estimated future operating
expenses and increased exploration costs in the fourth quarter of 2001. The
prices used for the estimation were $2.65 per Mcf for natural gas and $18.17 per
barrel for crude oil. The prices used for this estimation at December 31, 2000
were $10.14 per Mcf for natural gas and $26.06 per barrel for crude
oil.
At September 30, 2001, the Company recorded a non-cash impairment charge on its
U.S. domestic evaluated properties of $6,770,110 due to a significant decline in
the estimated present value of future net cash flows from these properties as a
result of lower natural gas and crude oil prices at September 30, 2001. The
prices used for the estimation were $2.20 per Mcf for natural gas and $23.50 per
barrel for crude oil.
During the year ended December 31, 2000, Beta participated in the drilling of 21
wells and the property acquisition and exploration costs associated with the
wells were transferred to evaluated properties. Amortization expense was
$2,604,328 or $1.35 per equivalent Mcf units of oil and gas produced. Oil is
converted to equivalent units of natural gas on the basis of one barrel of oil
to six equivalent Mcfs of natural gas.
F-14
During the year ended December 31, 1999, Beta participated in the drilling of 19
wells within the United States. The property acquisition and exploration costs
associated with the wells were transferred to evaluated properties. It was
determined that the total costs in the U.S. evaluated properties cost pool
exceeded their net realizable value. Accordingly, an impairment write-down of
$1,167,910 was recorded for the year ended December 31, 1999. Production
commenced during the year and depletion expense of approximately $901,573 was
recorded or $1.86 per equivalent Mcf units of oil and gas produced. Oil is
converted to equivalent units of natural gas on the basis of one barrel of oil
to six equivalent Mcfs of natural gas.
Due to the volatility of commodity prices and/or exploration expenditures with
no significant proved reserve additions, should natural gas and crude oil prices
decline in the future, even if only for a brief period of time, it is possible
that impairments of oil and gas properties could occur. The price measurement
date is on the last day of the quarter or year end and is required by SEC
rules.
Foreign - There was no activity outside of the United States for the year ended
December 31, 2001 and 2000.
During 1998, Beta, through its wholly owned subsidiary, BETAustralia, LLC
secured an option to participate for a 5% working interest in two petroleum
licenses covering 2,798,000 acres (approximately 4,372 square miles). Per the
terms of the option agreement, Beta exercised its option to earn a 5% working
interest by participating in the drilling of two offshore test wells in the
license areas. The wells were completed as dry holes. The property acquisition
and exploration costs associated therewith totaling $1,624,218 were transferred
to evaluated properties and charged to impairment expense during the year ended
December 31, 1998. The exploration licenses expired in December 1998. Additional
costs of $57,052 were transferred to and charged to impairment expense during
1999.
The results of operations for producing activities are provided below:
United States Foreign Total
------------ --------------- ---------------
2001:
Revenues ...................................... $ 12,788,115 $ -- $ 12,788,115
Production costs .............................. (3,469,194) -- (3,469,194)
Depreciation, depletion and amortization ...... (4,858,364) -- (4,858,364)
Impairment expense ............................ (13,805,035) -- (13,805,035)
------------ --------------- ---------------
Results of operations for producing activities
(excluding generative administrative,
financing costs and income taxes) ........ $ (9,344,478) $ -- $ (9,344,478)
============ =============== ===============
2000:
Revenues ...................................... $ 8,037,234 $ -- $ 8,037,234
Production costs .............................. (1,368,788) -- (1,368,788)
Depreciation, depletion and amortization ...... (2,604,328) -- (2,604,328)
------------ --------------- ---------------
Results of operations for producing activities
(excluding generative administrative,
financing costs and income taxes) ........ $ 4,064,118 $ -- $ 4,064,118
============ =============== ===============
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)
============ =============== ===============
F-15
Unevaluated oil and gas properties
At December 31, 2001, 2000 and 1999, unevaluated properties consist of
the following:
December 31,
2001 2000 1999
--------------- -------------- ----------------
Unproved $ 6,946,580 $ 8,547,825 $ 7,056,414
Exploration 6,054,863 4,902,522 5,035,213
--------------- -------------- ----------------
$13,001,443 $ 13,450,347 $ 12,091,627
=============== ============== ================
United States - As the Company's properties are evaluated through exploration,
they will be included in the amortization base. Costs of unevaluated properties
in the United States at December 31, 2001, 2000 and 1999 represent property
acquisition and exploration costs in connection with the Company's Louisiana and
Texas prospects. Unevaluated oil and gas properties are assessed at least
annually for impairment either individually or on an aggregate basis.
Unevaluated leasehold costs, including brokerage costs, are individually
assessed based on the remaining term of the primary leasehold. At December 31,
2001, unevaluated leasehold costs were impaired for $1,272,836 and transferred
to U.S. evaluated costs, or the full cost pool. For the remaining costs, which
include seismic and geological and geophysical, the Company estimates reserve
potential for the unevaluated properties using comparable producing areas or
wells and risk that estimate by 50-75%. Reserve estimations are more imprecise
for new or unevaluated areas. Consequently, should certain geological conditions
or factors exist, such as reservoir depletion, reservoir faulting, reservoir
quality, etc., but are unknown to the Company at the time of its assessment, a
materially different result could occur.
The current status of these prospects is that seismic has been acquired,
processed and reprocessed and is being interpreted on an ongoing basis on the
subject lands within the prospects. Drilling commenced on the prospects during
the first quarter of 1999 and will continue in future periods. As the prospects
are evaluated through drilling in future periods, the property acquisition and
exploration costs associated with the wells drilled will be transferred to
evaluated properties and become part of the amortization base.
Management anticipates that the planned activities for 2002 will enable the
evaluation for approximately 50% of the costs as of December 31, 2001 and the
remaining 50% of the costs will occur in 2003 and 2004.
Foreign - Costs of unevaluated properties outside the United States represents
costs in connection with the acquisition of properties in Australia. Management
expects 100% of this cost to be evaluated in 2002. The Company anticipates the
drilling of one well on this concession, in which it expects to retain 10% of
its current 25% interest, in 2002.
3. OTHER OPERATING PROPERTY AND EQUIPMENT:
As a result of the Merger, other operating property and equipment were acquired,
which included 40 miles of pipeline in Eastern Oklahoma. For the year ended
December 31, 2001 and 2000, the Company recorded depreciation expense of
$251,227 and $56,544, for these assets respectively. The Company recorded an
additional depreciation expense for other equipment, which includes furniture
and fixtures, of $67,306, $32,567 and $12,660 for the years ended December 31,
2001, 2000, and 1999, respectively.
At December 31, 2001 and 2000, support equipment with a net book value of
$347,172 was classified as idle. In management's opinion, the net book
value of the idle equipment is not in excess of its net realizable
value.
F-16
4. LONG-TERM DEBT:
Long-term debt consisted of the following:
2001 2000
--------------- ---------------
Notes payable under financing agreements for insurance premiums,
bearing interest at rates ranging from 8.50% to 9.75%, due in
monthly installments totaling $4,136 including interest, with
maturity dates beginning June 1, 2001 through December 31, 2002. $ 45,551 $ 79,832
Note payable under a revolving credit agreement, due March 15, 2003,
bearing interest at a LIBOR based rate plus 2.2% (4.32% at December
31, 2001), accrued interest payable monthly, collateralized by
substantially all oil and gas properties owned by one of the
Company's subsidiaries. Additionally, the Company has guaranteed
the debt. 13,634,652 13,784,650
Note payable, due in monthly installments of $1,230 including
interest maturing on December 19, 2003, collateralized by equipment.
25,931 38,761
--------------- ---------------
13,706,134 13,903,243
Less current portion (57,407) (89,209)
--------------- ---------------
$ 13,648,727 $ 13,814,034
=============== ===============
The $13,634,652 note at December 31, 2001 arises from a credit agreement with a
commercial bank that provides for maximum outstanding borrowings aggregating $25
million limited to a collateral borrowing base of $14,400,000, which will be
redetermined semi-annually. The Company is required to maintain certain
covenants of which the Company was in compliance at December 31,
2001.
Aggregate maturities required on long-term debt at December 31, 2001 are due in
future years as follows:
2002 $ 57,407
2003 13,648,727
2004 -
2005 -
2006 -
---------------
Total $ 13,706,134
===============
5. BRIDGE NOTES - NOTES PAYABLE:
During the year ended December 31, 1999 the Company completed the private
placement of a $3,000,000 bridge promissory note financing to three
institutional investors (the "1999 bridge financing"). In connection with the
1999 bridge financing, the Company granted the investors a security interest in
all of its assets. In addition, a total of 459,000 shares of the Company common
stock were issued in connection with the 1999 bridge financing. The $3,000,000
in bridge notes was repaid in full with accrued interest on July 7, 1999 from
the proceeds of the Company's initial public offering.
F-17
The Company received net cash proceeds of $2,835,000 from the bridge notes. The
estimated fair market value of 429,000 shares of common stock issued in
connection with the bridge note of $2,574,000 was treated as a discount and was
amortized over the term of the promissory notes using the interest method. The
estimated fair market value of 30,000 additional shares of common stock issued
per the terms of the bridge note of $180,000 was immediately expensed as
interest during the year ended December 31, 1999. Accordingly, the Company
incurred additional interest expense of $2,754,000 because of the common stock
issued in connection with the bridge notes. The debt issuance costs of the 1999
bridge financing of $89,100 were amortized as additional interest expense during
the year ended December 31, 1999.
6. COMMITMENTS AND CONTINGENCIES:
Lease Commitments -
The Company leases office space in Oklahoma and certain vehicles under long-term
operating leases. The Company's leases include the cost of real property taxes
and utilities. Insurance and routine maintenance are the Company's
responsibility.
Future minimum lease payments for all non-cancelable operating leases are as
follows:
YEARS ENDING DECEMBER 31, AMOUNT
------------------------- -------------
2002 $ 179,068
2003 159,967
2004 22,975
2005 5,927
2006 -
-------------
TOTAL $ 367,937
=============
Rent expense was $170,338, $125,640 and $33,000 for the years ended December 31,
2001, 2000 and 1999, respectively.
Contingencies - On November 29, 2000 in the District Court of Tulsa County,
State of Oklahoma, a Petition was filed by ONEOK Energy Marketing and Trading
Company, L.P. ("ONEOK"), plaintiffs, naming the Company and two wholly-owned
subsidiaries, Red River Field Services, L.L.C. and Red River Energy, L.L.C.
("Beta"), as defendants. In the lawsuit, the plaintiff alleges that Beta
discontinued selling gas to the plaintiff under a fixed price agreement and sold
the gas instead to other suppliers. Beta filed a counterclaim on January 24,
2001, alleging that the contract had been terminated pursuant to its terms for
nonpayment by the plaintiff for gas supplied prior to termination, and seeking
damages for the unpaid charges.
Subsequent to December 31, 2001, the Company has settled the above claim and
counterclaim with ONEOK through independent mediation. It was mutually agreed to
release all claims and Beta will pay ONEOK $43,000 in addition to the $282,096
of funds currently held by ONEOK. Each party will be responsible for their legal
fees and costs associated with this matter of which Beta's total legal fees were
approximately $85,600. Net of amounts due from joint interest partners, a
non-recurring charge of $205,415 was recorded to income in the year ended
December 31, 2001 related to the settlement.
In September 2001, the Company participated with a 62.5% interest in the
drilling of the Dore #1, Live Oak Prospect located in Vermillion Parish,
Louisiana. The well, which was drilled by a third-party contract drilling
company, was deemed non-commercial and plugged and abandoned. During plugging
operations, drilling fluid was discovered surfacing away from the well location
indicating an integrity issue with the well bore. All regulatory agencies were
notified and the Company, as operator of the well, is to conduct a groundwater
investigation to determine the extent of groundwater contamination, if any. The
estimated costs for the investigation is estimated to be approximately $270,000
and will be covered by the Company's pollution insurance coverage. If
contamination is present, groundwater remediation would be necessary. No cost
estimates for such remediation have been prepared at this time.
F-18
7. DERIVATIVE AND HEDGING ACTIVITIES:
In accordance with the transition provisions of SFAS No. 133, on January 1,
2001, in connection with Beta's hedging activities, the Company recorded as
cumulative effect adjustments a loss of $953,488 (net of $635,488 income tax) in
accumulated other comprehensive loss and a corresponding liability. Subsequent
to January 1, 2001, the Company recorded a gain of $734,031 (net of $489,353
income tax) in the first quarter ended March 31, 2001 and a gain of $219,457
(net of $146,305 income tax) in the second quarter ended June 30, 2001. Based on
the derivative contract date, all of the transition adjustments initially
recorded in accumulated other comprehensive loss were reclassified to earnings
in the second quarter of 2001.
For the twelve months ended December 31, 2001, the Company had a realized loss
of $340,048 relative to its hedging activities.
Natural Gas - At December 31, 2001, the Company had the following commodity
price hedging contracts outstanding as set forth below with respect to its 2001
and 2002 natural gas production. The hedging transactions are settled based upon
the average of the reported settlement prices on the NYMEX for the last three
trading days of a particular contract month.
NYMEX Contract Price per MMBtu
---------------------------------
Volume in Collars
Period MMBtus Floor Ceiling
Sept 01 - Feb 02 362,000 $3.50 $3.85
At December 31, 2001, the outstanding contracts had a fair market value of
$35,631 (net of $23,755 income tax) and accordingly, the Company recorded a
derivative asset for such amount. These contracts are costless and no net
premium is received in cash or as a favorable rate.
Crude Oil - At December 31, 2001, the Company had the following commodity price
hedging contracts outstanding as set forth below with respect to its 2001 and
2002 crude oil production. The hedging transactions are settled based upon the
average of the reported daily settlement prices per barrel for West Texas
Intermediate Light Sweet Crude Oil on the NYMEX for each trading day of a
particular contract month.
NYMEX Contract Price per Barrel
-------------------------------
Volume in Collars
Period Barrels Floor Ceiling
Oct 01- Mar 02 30,000 $25.00 $27.90
At December 31, 2001, the outstanding contracts had a fair market value of
$32,877 (net of $21,919 income tax) and accordingly, the Company recorded a
derivative asset for such amount. These contracts are costless and no net
premium is received in cash or as a favorable rate.
F-19
8. STOCKHOLDERS' EQUITY:
Preferred Private Placement - On June 29, 2001 the Company completed its Private
Placement Offering of Series A 8% Convertible Preferred Stock and common stock
purchase warrants, offered as units of one Preferred Share and one-half of one
Warrant at $9.25 per unit. Net proceeds received from the Offering were
approximately $5,041,528 net of estimated offering expenses, including brokers'
commissions and other fees and expenses of $547,862. The Company issued 604,272
Preferred Shares and 302,136 Warrants to purchase a like number of shares of
Beta's common stock at a price equal to the Offering price or $9.25 per share.
Brokers were issued 59,775 non-callable warrants as part of their commission.
All investors participating in the Offering were accredited. The proceeds were
used by the Company to help meet its capital requirements, including drilling
costs and for other corporate purposes.
The Preferred Shares may be converted by the holder at anytime at an exchange
rate of one share of the Company's common stock for each one Preferred Share
converted. The Preferred Shares will automatically convert into shares of the
Company's common stock on a one-share for one-share basis effective the first
trading day after the reported high selling price for Beta's common stock is at
least 150% of the per Unit offering price of $9.25 per share or $13.875 per
share for any 10 trading days.
The Preferred Shares will pay quarterly cash dividends commencing in the quarter
that the Preferred Shares are issued, at an annual rate of 8% per annum, simple
interest. If the Preferred Shares are automatically converted into common stock
or called by the Company within one year of the issuance each holder of the
Preferred shares will receive a full year's dividend less any dividends
previously paid during the year.
The Company has the unilateral right to redeem all or any of the outstanding
Preferred Shares from the date of issuance but must pay a premium if redeemed
within the first five years. The holders of the Preferred Shares will be
entitled to a liquidation preference equal to the stated value of the Preferred
Shares plus any unpaid and accrued dividends through the date of any liquidation
or dissolution of the Company. At December 31, 2001, the liquidation preference
was approximately $5,923,834. Warrants are non-transferable and may be exercised
at any time through June 29, 2006.
Treasury Stock - On September 19, 2001 the Company's Board of Directors
authorized a stock repurchase program for up to an aggregate of $1,000,000 of
the Company's common stock over the next four months. The repurchase program was
effective immediately. At December 31, 2001, the Company had reacquired 42,500
shares for a total cost of $198,920 or $4.68 per share.
The authorization to repurchase shares was facilitated in part by an Order
issued by the Securities and Exchange Commission on September 14, 2001. The
Order temporarily increased the flexibility with respect to certain SEC rules
pertaining to issuer stock repurchases. The timing and amount of shares actually
purchased will be determined at Beta management's discretion, based on market
conditions and other factors
Warrants -
The Company issued 56,000, 225,000 and 51,000 warrants to employees and
directors of the Company during the years ended December 31, 2001, 2000 and 1999
with exercise prices, equal or greater than the market price on the date of
grant, ranging from $5.00 per share to $10.25 per share. The warrants issued
vested immediately and expire between 2004 and 2006.
During the years ended December 31, 2000 and 1999, the Company issued 75,000 and
50,000 warrants with exercise prices of $7.75 and $6.00, of which 60,000
warrants were cancelled, in connection with an acquisition of unevaluated oil
and gas properties. The warrants were valued at $45,847 and $102,135 using the
Black- Scholes valuation model with a volatility ranging from 50.1% to 54.4%,
risk free interest rates ranging from 5.72% to 5.77% and an estimated time to
expire of three years. The warrants vest immediately and begin to expire in
2006.
During the year ended December 31, 1999, the Company issued 85,000 warrants in
connection with consulting and legal services received during the year. The
warrants have exercise prices ranging from $6.00 to $6.38, vested immediately,
and expire beginning in the year ended December 31, 2004. The warrants were
valued at $126,890 using the Black Scholes valuation model with a volatility of
54.4%, risk free interest rate ranging from 5.70% to 5.84%, and a two-year
period to expiration.
F-20
On June 21, 1999, certain warrant holders agreed to cancel 87,296 warrants to
purchase common stock consisting of 20,000 warrants exercisable at $5.00 per
share and 67,296 warrants exercisable at $7.00 per share. All of the canceled
warrants were non-callable with expiration dates on March 12, 2003. The warrants
were cancelled for no consideration pursuant to a request by the National
Association of Securities Dealers, the "NASD". The warrant holders were certain
NASD member firms and their employees who participated in Beta's 1998 private
placement, as well as Beta's legal counsel. The cancellation request was made
and complied with because the NASD determined that these warrants could be
deemed "underwriters compensation"; and the continued existence of these
warrants could result in the compensation for the initial public offering
exceeding the NASD guidelines.
The following table summarizes the number of shares reserved for the exercise of
common stock purchase warrants as of December 31, 2001:
AVG EXERCISE
NO. OF SHARES PRICE/SHARE
----------------- ------------
BALANCE, January 1, 1999 2,497,663 $ 5.24
Granted 319,122 6.48
Forfeited/Cancelled (87,296) 6.54
Exercised (446,142) 4.60
---------------- ------------
BALANCE, December 31, 1999 2,283,347 5.49
Granted 400,000 9.26
Forfeited/Cancelled (60,149) 7.75
Exercised (665,827) 4.68
---------------- ------------
BALANCE, December 31, 2000 1,957,371 6.46
Granted 469,915 9.02
Forfeited/Cancelled (50,000) 8.13
Exercised (57,621) 3.14
---------------- ------------
BALANCE, December 31, 2001 2,319,665 $ 7.05
================ ============
The Company is entitled to call certain warrants at any time after the date that
its common stock is traded on any exchange for a 10-day period at a target
price, ranging from $7.00 through $10.00. At December 31, 2001, 832,415 warrants
were callable with a weighted average exercise price of $8.44 per share. The
remaining 1,487,250 warrants outstanding are non-callable warrants with a
weighted average price of $6.27 per share. If not previously exercised, 474,257
warrants will expire in 2002, 769,587 warrants will expire in 2003, 460,906
warrants will expire in 2004, 191,000 warrants will expire in 2005, 408,915
warrants will expire in 2006 and 15,000 warrants will expire in
2007.
F-21
Stock Option Plan
In August 2000, the Company adopted the 1999 Incentive and Nonstatutory Stock
Option Plan (the 1999 plan) covering 700,000 shares that had previously been
approved by the Board of Directors in August 1999. The 1999 plan is a "dual
plan" which provides for the grant of both incentive stock options and
non-qualified stock options and was designed to attract and retain the services
of employees, officers, directors, and consultants. The price of the options
granted pursuant to the plan shall not be less than 100% of the fair market
value of the shares on the date of grant. Prices for incentive options granted
to employees who own 10% or more of the Company's stock is at least 110% of
market value at date of grant. The plan will be administered by a compensation
committee consisting of two or more disinterested non-employee board members who
will decide the vesting period of the options, if any, and no option will be
exercisable after ten years from the date granted. The stock option plan will
continue in effect for 10 years from August 20, 1999, unless sooner terminated
by the Board of Directors. Unless otherwise provided by the Board of Directors,
the stock options granted under the stock option plan will terminate immediately
prior to the consummation of a proposed dissolution or liquidation of the
Company.
During the year ended December 31, 2001, the Company granted 93,500 options,
under the 1999 Plan to certain employees at an average exercise price of $4.60
per share which was greater than the market price on the date of grant. The
options vested immediately and expire in 2011.
In December 2000, the Company granted options to purchase 135,000 shares of
common stock to employees under the 1999 plan. The options were granted with an
exercise price of $7.70 per share which was greater than the market price on the
date of grant. The options vested immediately and expire in 2009.
In September 2000, the Company granted options to purchase 51,000 shares of
common stock to employees under the 1999 plan. The options were granted with an
exercise price of $9.00 per share which was greater than the market price on the
date of grant. The options expire in 2009 and vest over three years.
During August 1999, the Company granted options to purchase 97,500 shares of
common stock to employees under the 1999 plan. The options did not become
effective until the 1999 stock option plan was approved by the shareholders. The
options were granted with an exercise price of $6.00 which represented an amount
in excess of 110% of the fair market value on the date of grant. The options
vested immediately and expire in 2009.
The following table sets forth activity for all options granted under the 1999
Plan:
AVG EXERCISE
NO. OF SHARES PRICE/SHARE
------------- ---------------
BALANCE, December 31, 1999 - -
Granted 283,500 $ 7.35
Forfeited/Cancelled (2,500) 6.00
Exercised (15,000) 6.00
------------- ---------------
BALANCE, December 31, 2000 266,000 $ 7.44
Granted 93,500 4.60
Forfeited/Cancelled - -
Exercised - -
------------- ---------------
BALANCE, December 31, 2001 359,500 $ 6.70
============== ===============
F-22
At December 31, 2001, 340,500 options to purchase shares were exercisable at
prices ranging from $4.00 to $9.00 per share. The remaining 19,000 options
outstanding will vest ratably through 2002 with an exercise price of $9.00 per
share.
If not previously exercised, the outstanding plan options will expire as
follows:
NO. OF AVG EXERCISE
PERIOD ENDED DECEMBER 31, SHARES PRICE/ SHARE
--------------------------- ------------ --------------
2009 80,000 $ 6.00
2010 186,000 8.06
2011 93,500 4.60
----------- --------------
359,500 $ 6.70
=========== ==============
As stated in Note 2, the Company has not adopted the fair value accounting
prescribed by FASB123 for employees. Had compensation cost for stock options
issued to employees been determined based on the fair value at grant date for
awards in 2001, 2000 and 1999 consistent with the provisions of FASB123, the
Company's net income (loss) and net income (loss) per share would have been
adjusted to the proforma amounts indicated below:
DECEMBER 31, DECEMBER 31, DECEMBER 31,
2001 2000 1999
--------------- --------------- --------------
Pro Forma net income (loss) $ (9,420,328) $ 900,618 $ (5,470,000)
=============== =============== ==============
Basic and diluted net income
(loss) per common share $ (.76) $ .08 $ (0.67)
=============== =============== ==============
The fair value of each option and warrant granted to employees was estimated on
the date of grant using the Black-Scholes option-pricing model using the
following assumptions: risk-free interest rates ranging from 5.07% to 6.05%,
expected life of two to three years; dividend yield of 0%; and expected
volatility ranging from 0% to 54.42%. The weighted-average fair value of the
options on the grant date for the years ended December 31, 2001, 2000 and 1999
was $1.23, $3.18 and $1.68 per share, respectively.
9. INCOME TAXES:
Income tax benefit (expense) for the indicated periods is comprised of the
following:
For the Years Ended December 31,
2001 2000 1999
------------- ------------- -------------
Current
Federal $ (17,000) $ (51,000) $ -
State (4,872) (243,300) -
------------- ------------- -------------
$ (21,872) $ (294,300) $ -
============= ============= =============
Deferred
Federal $ 2,367,562 - -
State 1,158,742 - -
------------- ------------- -------------
$ 3,526,304 $ - $ -
============= ============= =============
F-23
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,
2001 2000 1999
-------------- -------------- --------------
Amount of expected tax benefit
(expense) $ 4,267,175 $ (584,754) $ 1,830,697
Non-deductible expenses (870,390) (32,740) (14,866)
State taxes, net 839,213 (143,748) (800)
Change in valuation allowance (731,566) 175,473 (1,815,031)
Alternative minimum tax - (51,000) -
Utilization of net operating loss
carry-forwards - 342,469 -
-------------- -------------- --------------
$ 3,504,432 $ (294,300) $ -
============== ============== ==============
The components of the net deferred tax asset and (liability) recognized are as
follows:
For the Years Ended
DECEMBER 31,
2001 2000
--------------- ---------------
Long-term deferred tax assets (liabilities):
Net operating loss carry-forwards $ 4,883,674 $ 4,218,944
Other operating property-Equipment 1,508,444 1,478,797
Oil and gas properties (5,660,552) (9,224,045)
--------------- ----------------
731,566 (3,526,304)
Valuation allowance (731,566) -
--------------- ----------------
Net long-term deferred tax asset (liability) $ - $ (3,526,304)
=============== ================
At December 31, 2001, the Company had Federal net operating loss carry forwards
of approximately $12,651,100 which expire in the years 2012 through 2021. The
Company has California net operating loss carry forwards at December 31, 2001 of
$6,564,029 which begin to expire in 2007.
Utilization of the tax net operating loss carry-forwards may be limited in the
event a 50% or more change in ownership occurs within a three-year
period.
10. OTHER:
Related Party Transactions - For the years ended December 31, 1999 a director of
the Company was paid $75,000 pursuant to a consulting contract for management
and geologic evaluation services. In addition, the director subscribed to
350,000 shares of the Company's common stock at a price of $0.05 per share
("founder shares"). The Director became an employee of the Company
effective January 2000.
In 2001, the Company entered into an Exploration and Development Area of Mutual
Interest Agreement in Fremont County, Wyoming with a director of the Company.
The Company purchased certain geology and lease acreage approximating 1,627
acres in a prospect located therein for $154,800. The Company acquired a 75%
working interest with the director retaining a 25% working interest and up to a
5% overriding royalty interest. All future exploration and development costs
will be shared accordingly with the Company being responsible for 75% and the
director responsible for 25% of such costs. During 2001, the Company incurred
additional costs of approximately $166,600. In connection with the review of its
unevaluated properties for impairment, the Company recorded an impairment of
$127,229 based on remaining lease term.
F-24
Employment Contracts- The Company has executed an employment contract dated June
23, 1997 with its president who also serves as a director. The contract provides
for an indefinite term of employment at an annual salary of $150,000 commencing
in October of 1997 and an annual car allowance of up to $12,000. The contract
may be terminated by the Company without cause upon the payment of any of the
following:
(a) Options to acquire the common stock of the Company in an amount equal to
10% of the then issued and outstanding shares containing a five year term,
piggyback registration rights and an exercise price equal to 60% of the
fair market value of the shares during the sixty day period of time
preceding the termination notice, such amount not to exceed $3.00 per
share.
(b) A cash payment equal to two times the aggregate annual compensation.
(c) In the event of termination without cause, all unvested securities issued
by the Company to the Employee shall immediately vest and the Company shall
not have the right to terminate or otherwise cancel any securities issued
by the Company to the Employee.
Deferred Compensation - In 1998, the Company began to offer a simple individual
retirement account (IRA) plan for all employees meeting certain eligibility
requirements. Employees may contribute up to 3% of the employee's eligible
compensation. The Company's contribution to the plan for the years ended
December 31, 200 1, 2000 and 1999 was $31,377, $15,456 and $4,693,
respectively.
11. OTHER ASSETS:
Other assets of approximately $1,472,570 and $746,140 at December 31, 2001 and
December 31, 2000, respectively, consisted primarily of unapplied well
prepayments.
F-25
12. NET INCOME (LOSS) PER COMMON SHARE:
The following represents the calculation of net income (loss) per
common share:
2001 2000 1999
------------ ------------ ------------
Basic
Net income (loss) ............................. $ (9,046,084) $ 1,425,565 $ (5,384,403)
Less: preferred dividends ..................... (231,821) -- --
------------ ------------ ------------
Net income (loss) applicable to common
shareholders ............................... $ (9,277,905) $ 1,425,565 $ (5,384,403)
============ ============ ============
Weighted average number of shares ............. 12,368,373 10,616,692 8,160,000
============ ============ ============
Basic earnings (loss) per share ............... $ (.75) $ .13 $ (.66)
============ ============ ============
Diluted
Net income (loss) ............................. $ (9,046,084) $ 1,425,565 $ (5,384,403)
Plus: preferred dividends ..................... (231,821) -- --
------------ ------------ ------------
Net income (loss) applicable to common
shareholders ............................... $ (9,277,905) $ 1,425,565 $ (5,384,403)
============ ============ ============
Weighted average number of shares ........... 12,368,373 10,616,692 8,160,000
Common stock equivalent shares representing
shares issuable upon exercise of stock
options .................................... Antidilutive 24,646 --
Common stock equivalent shares representing
shares issuable upon exercise of warrants Antidilutive 640,075 --
Common stock equivalent shares representing
shares "as-if" conversion of preferred shares Antidilutive -- --
------------ ------------ ------------
Weighted average number of shares used in
calculation of diluted income (loss) per share 12,368,373 11,281,413 8,160,000
============ ============ ============
Diluted earnings (loss) per share ........... $ (.75) $ .13 $ (.66)
============ ============ ============
The following common stock equivalents were not included in the computation for
diluted earnings (loss) per share because their effects were
antidilutive.
Common Stock Equivalents: Shares
---------------------------------------- ----------
Options 43,848
Warrants 287,589
"As-if" conversion of Preferred stock 311,610
----------
643,047
==========
F-26
13. SUBSEQUENT EVENTS:
Subsequent to December 31, 2001, the Company entered into the following
commodity price hedging contracts as set forth below with respect to a portion
of its natural gas and crude oil production for 2002 and 2003. The hedging
transactions are settled based upon the average of the reported settlement
prices on the NYMEX for the last three trading days of a particular contract
month.
Natural Gas:
NYMEX Contract Price per MMBtu
---------------------------------
Volume in Collars
Period MMBtus Floor Ceiling
March 02 - Feb 03 1,460,000 $2.30 $2.91
The hedging transactions are settled based upon the average of the reported
settlement prices on the NYMEX for the last three trading days of a particular
contract month. Based on the Company's production rate at December 31,
2001, this represents approximately 53% of the Company's natural gas
production.
Crude Oil:
NYMEX Contract Price per Barrel
---------------------------------
Volume in Collars
Period Barrels Floor Ceiling
April 02- Mar 03 60,000 $20.50 $21.75
The hedging transactions are settled based upon the average of the reported
daily settlement prices per barrel for West Texas Intermediate Light Sweet Crude
Oil on the NYMEX for each trading day of a particular contract month. Based on
the Company's production rate at December 31, 2001, this represents
approximately 43% of the Company's crude oil production.
14. UNAUDITED SUPPLEMENTARY OIL AND NATURAL GAS INFORMATION:
The following supplementary information is presented in compliance with United
States Securities and Exchange Commission ("SEC") regulations and FASB Statement
No. 69, "Disclosures About Oil and Gas Producing Activities," and is not covered
by the report of the Company's independent auditors.
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions. Proved developed
oil and gas reserves are those reserves expected to be recovered through
existing wells with existing equipment and operating methods. The reserve data
is based on studies prepared by the Company's independent consulting
petroleum engineers. Reserve estimates require substantial judgment on the part
of petroleum engineers resulting in imprecise determinations, particularly with
respect to new discoveries. Accordingly, it is expected that the estimates of
reserves will change as future production and development information become
available. At December 31, 2001, the Company's proved oil and gas reserve
are located in Oklahoma, Texas, Louisiana and Kansas. The following table
presents estimates of the Company's net proved oil and gas reserves and
changes therein for the years ended December 31, 2001, 2000 and
1999:
F-27
Changes in Quantities of Proved Petroleum and Natural Gas Reserves (unaudited)
PROVED RESERVES
OIL (BBLS) GAS (MCF)
--------------- -------------
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 (32,614) (1,726,416)
Revision of previous estimates 78,646 (315,104)
--------------- ------------
Proved reserves, December 31, 2000 813,970 19,418,000
Extensions and discoveries 279,204 9,691,000
Purchase of minerals in place 12,433 -
Sale of minerals in place (1,831) (420,000)
Production (114,271) (2,512,484)
Revision of previous estimates (152,677) (1,466,516)
--------------- ------------
Proved reserves, December 31, 2001 836,828 24,710,000
=============== ============
PROVED DEVELOPED RESERVES
OIL (BBLS) GAS (MCF)
--------------- ------------
Balance - December 31, 1998 1,461 1,596,740
Balance - December 31, 1999 13,201 4,170,000
Balance - December 31, 2000 813,970 19,115,000
Balance - December 31, 2001 707,751 16,654,000
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 net cash flows and changes therein relating to
estimated proved reserves. The Company has followed these guidelines which are
briefly discussed below.
Future cash inflows and future production and development costs are determined
by applying year-end prices and costs to the estimated quantities of oil and gas
to be produced. Estimates of future income taxes are computed using current
statutory income tax rates including consideration for estimated future
statutory depletion and tax credits. The resulting net cash flows are reduced to
present value amounts by applying a 10% discount factor.
The assumptions used to compute the standardized measure are those prescribed by
the Financial Accounting Standards Board and, as such, do not necessarily
reflect the Company's expectations for actual revenues to be derived from those
reserves nor their present worth. The limitations inherent in the reserve
quantity estimation process, as discussed previously are equally applicable to
the standardized measure computations since those estimates are the basis for
the valuation process.
F-28
The following summary sets forth the Company's future net cash flows relating to
proved oil and gas reserves as of December 31, 2001, 2000 and 1999 based on the
standardized measure prescribed in Statement of Financial Accounting Standard
No. 69:
YEAR ENDED DECEMBER 31,
2001 2000 1999
--------------- --------------- ---------------
Future cash inflows $ 79,924,007 $ 204,303,798 $ 9,141,659
Future costs-
Production (27,624,047) (28,592,624) (905,242)
Development (5,742,783) (1,123,359) (701,771)
--------------- --------------- ---------------
Future net cash inflows before
income tax 46,557,177 174,587,815 7,534,646
Future income tax - (49,221,755) -
--------------- --------------- ---------------
Future net cash flows 46,557,177 125,366,060 7,534,646
10% discount factor (15,262,165) (53,907,406) (1,521,674)
--------------- --------------- ---------------
Future net cash flows $ 31,295,012 $ 71,458,654 $ 6,012,972
=============== =============== ===============
Changes in the Standardized Measure (unaudited) - The following are the
principal sources of changes in the standardized measure of discounted future
net cash flows for the years ended December 31, 2001, 2000 and 1999:
YEAR ENDED DECEMBER 31,
2001 2000 1999
---------------- ---------------- ---------------
Standardized measure,
beginning of year $ 71,458,654 $ 6,012,972 $ 1,716,608
Sale of oil and gas produced, net
of production costs (9,318,921) (6,668,446) (1,117,942)
Purchase of minerals in place 92,246 77,595,310 -
Sales of minerals-in-place (1,721,355) - -
Extensions and discoveries 14,887,920 15,200,178 6,374,495
Changes in income taxes, net 32,978,576 (28,056,400) -
Changes in prices and costs (74,018,682) 21,485,597 447,063
Changes in development costs (4,269,818) 78,373 (443,525)
Accretion of discount 7,145,865 601,297 171,661
Revisions of estimates and other (5,939,473) (14,790,227) (1,135,388)
---------------- ---------------- ----------------
Standardized measure, end of year $ 31,295,012 $ 71,458,654 $ 6,012,972
================ ================ ================
F-29
SIGNATURES Pursuant to the requirements of Section 13 or 15 (d) of the
Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned thereunto duly authorized on the 30th
day of March, 2001.
BETA OIL & GAS, INC.
Date: March 28, 2002 By: /s/ Steve A. Antry
---------------------------
Steve A. Antry
Chairman of the Board
of Directors and President
By: /s/ Joseph L. Burnett
------------------------------
Joseph L. Burnett
Chief Financial Officer, and
Principal Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
Signature Title Date
/s/ Steve Antry Chairman of the March 28, 2002
- --------------------------
Steve Antry Board of Directors
and President
/s/ Joseph L. Burnett Chief Financial Officer, March 28, 2002
- --------------------------
Joseph L. Burnett and Principal Accounting Officer
/s/ R.T. Fetters Director March 28, 2002
- --------------------------
R.T. Fetters
/s/ Joe C. Richardson, Jr. Director March 28, 2002
- --------------------------
Joe Richardson Jr.
/s/ John P. Tatum Director March 28, 2002
- --------------------------
John P. Tatum
/s/ Robert C. Stone, Jr. Director March 28, 2002
- --------------------------
Robert C. Stone, Jr.
38
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
3.1 Original Articles of Incorporation of Registrant incorporated by reference
to Exhibit 3.1 of Beta's S-1 Registration Statement No. 333-68381
filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/data/1059324/
001059324-98-000005.txt).
3.2 Amended and Restated Bylaws of the Registrant, Dated October 29, 1998,
incorporated by reference to Exhibit 3.2 of Beta's S-1 Registration
Statement No. 333-68381 filed December 4, 1998 at
(http://www.sec.gov/Archives/edgar/data/1059324/0001059324-98-000005.txt).
3.3 Certificate of Amendment of Articles of Incorporation of the Registrant,
dated August 28, 2000, incorporated by reference to Exhibit 3.1 of Beta's
S-1 Registration Statement No. 333-68381 filed December 4, 1998 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt)
10.1 Formosa Grande Prospect Agreement, Dated August 1, 1997, incorporated by
reference to Exhibit 10.1 of Beta's S-1 Registration Statement No. 333-
68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/data/
1059324/0001059324-98-000005.txt).
10.2 Texana Prospect Agreement, Dated July 15, 1997, incorporated by reference
to Exhibit 10.2 of Beta's S-1 Registration Statement No. 333-68381 filed
December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/
1059324/0001059324-98-000005.txt).
10.3 Ganado Prospect Agreement, Dated November 1, 1997, incorporated by
reference to Exhibit 10.3 of Beta's S-1 Registration Statement No.
333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/
data/ 1059324/0001059324-98-000005.txt).
10.4 T.A.C. Resources Agreement, Dated January 21, 1998, incorporated by
reference to Exhibit 10.4 of Beta's S-1 Registration Statement No.
333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/
data/ 1059324/0001059324-98-000005.txt).
10.5 Lapeyrouse Prospect Agreement, Dated October 13, 1997, incorporated by
reference to Exhibit 10.5 of Beta's S-1 Registration Statement No.
333-68381 filed December 4, 1998 at (http://www.sec.gov/Archives/edgar/
data/ 1059324/0001059324-98-000005.txt).
10.6 Rozel (Transition Zone) Prospect Agreement, Dated February 24,1998,
incorporated by reference to Exhibit 10.6 of Beta's S-1 Registration
Statement No. 333-68381 filed December 4, 1998 at (http://www.sec.gov/
Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.7 Stansbury Basin (Australia) Prospect Agreement, Dated February 1998,
incorporated by reference to Exhibit 10.7 of Beta's S-1 Registration
Statement No. 333-68381 filed December 4, 1998 at (http://www.sec.gov/
Archives/edgar/ data/1059324/0001059324-98-000005.txt).
10.9 Steve Antry Employment Agreement, Dated June 23,1997, incorporated by
reference to Exhibit 10.9 of Beta's S-1 Registration Statement No. 333-
68381 filed December 4, 1998 at(http://www.sec.gov/Archives/
edgar/ data/1059324/0001059324-98-000005.txt)
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10.14BWC Prospect Agreement, Dated April 1, 1998, incorporated by reference to
Exhibit 10.14 of Beta's S-1 Registration Statement No. 333-68381 filed
December 4, 1998 at ( http://www.sec.gov/Archives/edgar/data/
1059324/0001059324-98-000005.txt).
10.19Redfish Prospect Agreement Dated January 6, 1999, incorporated by
reference to Exhibit 10.19 of Beta's Amendment No. 2 to S-1/A Registration
Statement No. 333-68381 filed May 3, 1999 at (http://www.sec gov/
Archives/edgar/data/1059324/0001059324-99-000011.txt).
10.20 Shark Prospect Agreement Dated January 6, 1999, incorporated by reference
to Exhibit 10.20 of Beta's Amendment No. 2 to S-1/A Registration
Statement No. 333-68381 filed May 3, 1999 at (http://www.sec.gov/Archives
/edgar/data/1059324/0001059324-99-000011.txt).
10.21 Cheniere Energy, Inc. Option Agreement Dated January 6, 1999,
incorporated by reference to Exhibit 10.21 of Beta's Amendment No. 2 to
S-1/A Registration Statement No. 333-68381 filed May 3, 1999 at
(http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.22 Dyad-Australia, Inc. Agreement Dated January 25, 1999, incorporated by
reference to Exhibit 10.22 of Beta's Amendment No. 2 to S-1/A
Registration Statement No. 333-68381 filed May 3, 1999 at
(http://www.sec.gov/Archives/edgar/data/1059324/0001059324-99-000011.txt)
10.24Northeast Hitchcock Agreement Dated July 30, 1999, incorporated by
reference to Exhibit 10.24 of Beta's Form 10-K/A for the year 1999
filed March 30, 2000 at ( http://www.sec.gov/Archives/edgar/data/1059324/
0001059324-00-000007.txt)
10.25Sarah White Agreement Dated July 30, 1999, incorporated by reference to
Exhibit 10.25 of Beta's Form 10-K/A for the year 1999 filed March 30,2000
at http://www.sec.gov/Archives/edgar/data/1059324/0001059324-00-000007.txt)
10.27 Revised Joint Development Agreement dated August 8, 2000 between Red
River Energy, L.L.C. and Avalon Exploration, Inc., incorporated by
reference to Exhibit 10.27 of Beta's Third Quarter Form 10-Q filed
November 14, 2000 at ( http://www.sec.gov/Archives/edgar/ data/1059324/
000105932400000042/0001059324-00-000052.txt).
10.29Mushroom Project Participation Agreement, Austin and Waller Counties,
Texas, dated June 14, 2000, incorporated by reference to Exhibit 10.29 of
Beta's Form 10-K for the year 2000 filed April 2, 2001 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt).
10.30Starboard Area Letter Agreement, Terrebone Parish, Louisiana dated June
16, 2000 incorporated by reference to Exhibit 10.30 of Beta's Form
10-K for the year 2000 filed April 2, 2001 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt).
10.31First Amended and Restated Revolving Credit Agreement between Bank of
Oklahoma and Red River Energy, LLC dated March 30, 1999, incorporated by
reference to Exhibit 10.31 of Beta's Form 10-K for the year 2000 filed
April 2, 2001 at (http://www.sec.gov/Archives/edgar/data/
1059324/000102189001500087/ 0001021890-01-500087.txt).
10.32First Amendment to First Amended and Restated Revolving Credit Agreement
between Bank of Oklahoma and Red River Energy, LLC dated February 1, 2000,
incorporated by reference to Exhibit 10.32 of Beta's Form 10-K for the
year 2000 filed April 2, 2001 at (http://www.sec.gov/Archives/edgar/data/
1059324/000102189001500087/0001021890-01-500087.txt).
10.33Second Amendment to First Amended and Restated Revolving Credit Agreement
between Bank of Oklahoma and Red River Energy, LLC dated June 15, 2000,
incorporated by reference to Exhibit 10.33 of Beta's Form 10-K for the
year 2000 filed April 2, 2001 at (http://www.sec.gov/Archives/edgar/
data/1059324/000102189001500087/0001021890-01-500087.txt).
10.34Third Amendment to First Amended and Restated Revolving Credit Agreement
between Bank of Oklahoma and Beta Oil & Gas, Inc. dated March 19,
2001, incorporated by reference to Exhibit 10.34 of Beta's Form 10-K
for the year 2000 filed April 2, 2001at (http://www.sec.gov/Archives/edgar/
data/1059324/000102189001500087/0001021890-01-500087.txt).
10.35Form of Placement Agent Agreement for Preferred Placement Offering dated
March 15, 2001, incorporated by reference to Exhibit 10.35 of Beta's Form
10-K for the year 2000 filed April 2, 2001 at
(http://www.sec.gov/Archives/edgar/data/1059324/000102189001500087/
0001021890-01-500087.txt).
10.36 Letter Agreement Between Avalon Exploration, Inc. and Beta Oil & Gas,
Inc. dated September 7,2001 amending Revised Joint Development Agreement
dated August 8, 2000 between Red River Energy, L.L.C. and Avalon
Exploration, Inc., incorporated by reference to Exhibit 10.27 of Beta's
Third Quarter Form 10-Q filed November 14, 2000.
21 List of Subsidiaries incorporated by reference to Exhibit 21 of Beta's
Form 10-K for the year 2000 filed April 2, 2001 at (http://www.sec.gov/
Archives/edgar/data/1059324/000102189001500087/0001021890-01-500087.txt).
23.2 Consent of Hein + Associates, LLP. dated March 28, 2002
23.3 Consent of Ryder Scott and Associates dated March 28, 2002
99 The Amended 1999 Incentive and Nonstatutory Stock Option Plan, incorporated
by reference to Exhibit 99 of Beta's 14A Definitive Proxy Statement
dated and filed August 14, 2000 at (http://www.sec.gov/Archives
/edgar/data/1059324/000105932400000042/0001059324-00-000042-0001.htm).
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