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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