================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION ------------------------------------ WASHINGTON, D.C. 20549 ------------------------------------ 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, 2000 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, 2001, 12,361,951 shares of the registrant's common stock were outstanding. The aggregate market value of such common stock held by non-affiliates was approximately $68,603,608 based on the reported closing sales price of $8.00 on the Nasdaq Market on that date. Certain sections of the registrant's annual proxy statement for the 2001 annual meeting of stockholders on or about June 2, 2001 is incorporated by reference into Part III. Exhibit table is on page 40. ================================================================================
December 31, 2000 December 31, 1999
United States ......... Foreign United States Foreign
Capitalized costs-
Evaluated properties .............$ 41,429,542 $ 1,680,921 $ 8,128,928 $ 1,681,270
Unevaluated properties ..............13,326,778 123,569 11,973,532 118,095
Less- Accumulated
depreciation, depletion,
amortization and impairment (4,673,635) (1,681,270) (2,115,957) (1,681,270)
------------ ------------ ------------ ------------
$ 50,082,685 $ 123,220 $ 17,986,503 $ 118,095
============ ============ ============ ============
Unevaluated oil and gas properties - United States
As our properties are evaluated through exploration, they will be included
in the amortization base. Costs of unevaluated properties in the United States
at December 31, 2000 and 1999 represent property acquisition and exploration
costs in connection with our Louisiana, Texas and Oklahoma prospects. The
prospects and their related costs in unevaluated properties have been assessed
individually and no impairment charges were considered necessary for the United
States properties for any of the periods presented. The current status of these
prospects is that seismic has been acquired, processed and is currently being
interpreted on the subject lands within the prospects. Drilling commenced on the
prospects in the first quarter of 1999. As the prospects are evaluated through
drilling in future periods, the property acquisition and exploration costs
associated with the wells drilled will be transferred to evaluated properties
where they will be subject to amortization.
Unevaluated oil and gas properties - Foreign
Unevaluated costs as of December 31, 2000, outside the United States
represent costs in connection with the evaluation and proposed acquisition of
one or more exploration blocks in Australia.
Evaluated Properties - United States
The property acquisition and exploration costs associated with the wells
drilled (completed or plugged and abandoned) are transferred to evaluated
properties. Total cost in evaluated properties did not exceed their net
realizable value at December 31, 2000. During the year ended December 31, 2000
we participated in the drilling of 21wells within the United States. At December
31, 2000, evaluated property cost was $41,429,542 which included $28,371,531
associated with the RRE Merger. No impairment was recorded for 2000. It was
determined that the total costs in evaluated properties of $8,128,928 as of
December 31, 1999 exceeded their net realizable value by $1,167,910.
Accordingly, an impairment charge for this amount was recorded for the year
ended December 31, 1999. Production commenced during the period and depletion
expense of $901,573 was recorded.
Evaluated Properties - Foreign
During 1998, Beta, through its wholly owned subsidiary, BETAustralia, LLC
secured an option to participate for a 5% working interest in two petroleum
licenses covering 2,798,000 acres (approximately 4,372 square miles). Per the
terms of the option agreement, Beta exercised its option to earn a 5% working
interest by participating in the drilling of two offshore test wells in the
license areas. The wells were completed as dry holes. The property acquisition
and exploration costs associated therewith totaling $1,624,218 were transferred
to evaluated properties and charged to impairment expense during the year ended
December 31, 1998. The exploration licenses expired in December 1998. Property
acquisition and exploration costs associated with foreign prospects totaling
$57,052 were transferred to evaluated properties and charged to impairment
expense during the year ended December 31, 1999. Beta has generated no revenues
from its foreign properties to date.
For further information on oil and gas operations, please see Item 8.
Financial Statements and Supplementary Data, Note 2. Acquisitions And Oil And
Gas Operations.
Principal Products
Our principal products are natural gas and crude oil.
Patents, Trademarks, Licenses, Franchises and Concessions Held
Permits, licenses and oil and gas leases are important to our operations,
as they allow the search for the extraction of any oil, gas and minerals
discovered on the areas covered. See further, Item 2 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 97% 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.
2000 1999
------------ ------------
IP Petroleum 31% 53%
Duke Energy 19% -
Cokinos Energy 13% 38%
Allegro Investments 12% -
We do not believe the loss of any one of our purchasers would materially
affect our ability to sell the oil and gas we produce. Other purchasers are
available in our areas of operations.
We are not obligated to provide a fixed and determinable quantity of oil or
natural gas under any existing arrangements or contracts other than the contract
discussed in Item 3. Legal Proceedings. We currently have a hedge arrangement
covering approximately 2,000 Mmbtu/d at a price of $3.08 per Mmbtu for the
period July 2000 through June 2001. The volume covered represents approximately
22% of our total daily production on an Mcf equivalent basis. We expect to use
hedge arrangements on a limited basis to realize commodity pricing which we
consider favorable at the time.
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 the 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.
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.
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. 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.
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.
Drilling and completion of oil and gas wells is hazardous and involves a
high degree of risk. In addition to the substantial risk that wells drilled will
not be productive, hazards such as unusual or unexpected formations, pressures,
down-hole fires, mechanical failures, blowouts and loss of circulation of
drilling fluids are inherent in oil and gas exploration. Even though a well is
completed and is found to be productive, water, sulfur, or other deleterious
substances may also be produced that may impair or prevent production or impair
or prevent the marketing of such production. Drilling operations may also be
susceptible to delays caused by inclement weather and the resulting condition of
the terrain. If any of such hazards and delays are encountered while conducting
operations, substantial unbudgeted and unexpected costs may be incurred.
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.
We are a non-operating working interest owner in 37% and operator in the
balance of the producing wells in which we have an interest. 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.
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.
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 17 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 $9,106 per month. A regional Gulf
Coast office is also maintained in Houston, Texas. We also have two field
offices located in South Tulsa County and Edmond, Oklahoma.
Producing Wells Acreage
---------------------------------------------- ---------------------------------------------------------
Oil Gas Developed Undeveloped
Gross Net (1) Gross Net (1) Gross Net (2) Gross Net
------- --------- -------- --------- ----------- ----------- ----------- -----------
Texas 8 .66 44 7.21 22,827.3 1,373.3 37,724.7 14,379.8
Oklahoma 80 58.39 115 79.39 54,320.9 42,051.5 2,860.5 2,804.4
Louisiana - - 6 .74 7,573.9 854.8 9,250.6 598.9
Kansas 19 18.79 2 2.00 6,889.5 3,681.1 640.0 640.0
California - - 1 .30 318.0 95.6 - -
------- --------- -------- --------- ----------- ----------- ----------- -----------
107 77.84 168 89.64 91,929.6 48,056.3 50,475.8 18,423.1
======= ========= ======== ========= =========== =========== =========== ===========
(1) Net wells are computed by multiplying the number of gross wells by our
working interest in the gross wells.
(2) Net acres are computed by multiplying the number of gross acres by our
working interest in the gross acres.
At December 31, 2000, approximately 10,138 gross acres and 4,279 net acres
will expire in 2001.
In addition to the interests we own in developed and undeveloped acreage,
at December 31, 2000 we have an option, which expires April 16, 2002 to acquire
interest in an additional 10,032 gross (3,344 net) acres in Jackson County,
Texas.
OIL AND NATURAL GAS RESERVES
At December 31, 2000, we had proved reserves of 814.0 Mbbls of oil and 19.4
Bcf of gas as estimated by Ryder Scott and Company, an independent engineering
firm. These reserves are located entirely within the United States. The
following table sets forth, at December 31, 2000, the present value of our
future net revenues (revenues less production and development cost) before
income taxes attributable to these reserves.
Proved Proved
Developed Undeveloped Total Proved
---------------- ---------------- -------------------
Oil (Bbls) - 813,970
813,970
Gas (Mcf) 19,115,000 303,000 19,418,000
Future Net Revenues (before income taxes) $ 172,269,015 $ 2,318,800 $ 174,587,815
================ ================ ===================
Present value of Future Net Revenue
(before income taxes) $ 98,759,975 $ 1,439,313 $ 100,199,288
================ ================ ===================
The above figures do not reflect the future net revenues before income
taxes and the present value of future net revenues, discounted at 10%, for the
Company's McIntosh gathering system, which were $7,736,205 and $4,679,377,
respectively.
For purposes of estimating the above cash flows, estimates were made of
quantities of proved reserves and the periods during which they are expected to
be produced. Future cash flows were computed by applying year-end prices to
estimated annual future production from proved oil and gas reserves. The average
year-end price for oil and natural gas was $26.80/Bbl and $9.23/Mbtu at December
31, 2000. Future development and production costs were computed by applying
year-end costs to be incurred in producing and further developing the proved
reserves. The estimated future net revenue was computed by application of a 10%
discount factor. The calculations assume the continuation of existing economic,
operating and contractual conditions. However, such arbitrary assumptions have
not proven to be the case in the past. Other assumptions of equal validity could
give rise to substantially different results.
For additional information on our oil and gas reserves, please refer to
Item 8. Financial Statements And Supplementary Data, Note 13. Unaudited
Supplementary Oil And Natural Gas Information.
Our oil and gas reserves are not subject to any long-term supply
arrangement with foreign governments or authorities. Our estimated reserves have
not been filed with or included in reports to any federal agency other than the
SEC and U.S. Department of Energy, FORM EIA-23, Annual Survey of Domestic Oil
and Gas Reserves for 2000.
DRILLING ACTIVITY
For the period indicated, the following table sets forth the results of our
drilling activities in the fiscal years ended December 31, 2000, 1999 and 1998:
Years Ended December 31,
--------------------------------------------------------------------------
2000 1999 1998
Gross Net Gross Net Gross Net
-------- -------- --------- ---------- --------- ---------
Exploratory:
Productive 14 2.24 12 1.75 2 .84
Dry 5 1.13 9 2.42 6 1.13
-------- -------- --------- ---------- --------- ---------
Total Exploratory 19 3.37 21 4.17 8 1.97
Development:
Productive 2 .26 - - - -
Dry - - - - - -
-------- -------- --------- ---------- --------- ---------
Total Development 2 .26 - - - -
Total:
Productive 16 2.50 12 1.75 2 .84
Dry 5 1.13 9 2.42 6 1.13 9
-------- -------- --------- ---------- --------- ---------
Total 21 3.63 21 4.17 8 1.97
======== ======== ========= ========== ========= =========
Subsequent to December 31, 2000, we have drilled 10 gross exploratory
wells, 2 net wells, of which 7 gross wells, 1.3 net wells were discoveries and 3
gross wells, .6 net wells, were dry holes. Currently 5 gross wells, .9 net
wells, are drilling or waiting on completion.
PRICE AND PRODUCTION DATA
We commenced sales of oil and gas in 1999. Our average sales price, oil and
natural gas production volumes and average production cost for each Mcf
equivalent of production for the periods indicated were as follows:
Year Ended December 31,
-------------------------------------
2000 1999
----------------- ---------------
Oil production (Bbl) 32,617 1,822
Gas production (Mcf) 1,726,416 475,065
Average sales price:
Oil (per Bbl) $ 30.57 $ 23.03 $ $
Gas (per Mcf) $ 4.08 $ 2.44
Average production cost per McfEQ $ .71 $ 0.17
Reflects the impact of gas hedge which reduced our 2000 total average gas
price per Mcf by $ .27.
The above well information excludes five wells in which we have only a
royalty interest.
The components of production costs may vary substantially among wells
depending on the methods of recovery and other factors, but generally include
production and ad valorem taxes, repairs and maintenance, labor and utilities.
2000 High Low
---- ---- ---
1st Quarter.......... $ 10.5625 $ 6.5312
2nd Quarter.......... 10.8750 7.7500
3rd Quarter.......... 12.0000 7.7500
4th Quarter.......... 9.3750 6.8125
1999
1st Quarter.......... N/A N/A
2nd Quarter.......... N/A N/A
3rd Quarter.......... 6.6875 4.2500
4th Quarter.......... 8.6250 5.9375
Approximately 271 shareholders of record and approximately 1,978 beneficial
owners as of March 15, 2001 held the common stock. In many instances, a
registered shareholder is a broker or other entity holding shares in street name
for one or more customers who beneficially own the shares.
Recent Sales of Unregistered Securities
We issued and sold the following securities without registration under the
Securities Act of 1933, as amended ("Securities Act"), for the quarter ended
December 31, 2000:
1. On October 1, 2000 we issued 50,000 shares upon the exercise of
warrants to purchase common stock to an outside director. The
certificates representing the shares issued bear a restrictive legend
prohibiting transfer without registration under the Securities Act or
the availability of an exemption from registration and "stop transfer"
instructions were issued to the transfer agent.
2. On October 15, 2000 we issued 60,000 shares upon the exercise of
warrants to purchase common stock to an outside broker for services
rendered. The certificates representing the shares issued bear a
restrictive legend prohibiting transfer without registration under the
Securities Act or the availability of an exemption from registration
and "stop transfer" instructions were issued to the transfer agent. The
shares have since been rescinded.
3. On October 16, 2000 we issued 15,000 shares upon the exercise of
warrants to purchase common stock to an outside broker for services
rendered. The certificates representing the shares issued bear a
restrictive legend prohibiting transfer without registration under the
Securities Act or the availability of an exemption from registration
and "stop transfer" instructions were issued to the transfer agent.
4. On December 8, 2000 we issued 135,000 shares upon the exercise of
options to purchase common stock pursuant to a 1999 Incentive and
Nonstatutory Stock Option Plan for our employees. The certificate
representing the shares bear a restrictive legend prohibiting transfer
without registration under the Securities Act or the availability of an
exemption from registration and "stop transfer" instructions were
issued to the transfer agent.
In connection with the issuance of the above noted securities, we relied
upon Section 4(2) of the Securities Act in claiming exemption for the
registration requirement of the Securities Act. All of the persons to whom the
securities were issued were sophisticated persons who had full information
concerning our business affairs and each acquired the shares for investment
purposes. The certificates representing the shares issued bear a restrictive
legend prohibiting transfer without registration under the Securities Act or the
availability of an exemption from registration. "Stop transfer" instructions
were issued to the transfer agent.
Item 6. Selected Financial Data
Summary Financial Information for Beta
The following tables presents selected historical financial data derived
from our Financial Statements as well as selected historical quarterly financial
data. The following data is only a summary and should be read with our
historical financial statements and related notes contained in this document.
The acquisition of RRE in 2000 affected the comparability between the Financial
Data for the periods presented.
For the years ended December 31, The period from
inception (June
6, 1997) through
December 31, 1997
2000 1999 1998
--------------- --------------- --------------
Income Statement Data:
Operating revenues ....... $ 8,357,867 $ 1,199,480 $ -- $ --
Operating expense ........ 1,516,113 81,538 -- --
General and administrative 2,141,005 1,418,240 746,769 245,452
Impairment expense ....... -- 1,224,962 1,670,691 --
Depreciation and
depletion expense ....... 2,693,439 914,233 11,883 1,530
Interest expense ......... 393,008 2,966,651 -- --
Net income (loss) ........ 1,425,565 (5,384,403) (2,384,500) (201,573)
Earnings (loss) per share:
Basic .................... $ .134 $ (.66) $ (.37) $ (.05)
Diluted .126 (.66) (.37) (.05)
Weighted average common shares and
equivalent outstanding:
Basic .................... 10,616,692 8,160,000 6,366,923 4,172,662
Diluted .................. 11,281,413 8,160,000 6,366,923 4,172,662
Balance sheet data:
Working capital ................... $ 3,533,237 $ 2,034,268 $ (96,457) $ 3,117,351
Total assets ...................... 58,466,152 20,881,475 13,618,471 9,921,057
Total long term debt .............. 13,814,034 27,939 -- --
Stockholder's equity .............. 40,060,406 20,588,237 13,299,342 9,050,210
Proved Reserves
Oil (Mbbls) 814.0 13.2 1.4 --
Gas (Mmcf) ................... 19,418.0 4,170.0 1,596.7 --
Total (Mmcfe) ................ 24,302.0 4,249.2 1,605.1 --
Present value of estimate future
net revenues before income tax
discounted at 10% ................. $ 100,199,288 $ 6,012,972 $ 1,716,608 $ --
SELECTED QUARTERLY ....... For the quarter ended
FINANCIAL DATA
(In Thousands of Dollars) March 31 June 30 September 30 December 31
-------- ---------- -------- ---------
2000
Revenues ................. $ 940.3 $ 1,082.3 $ 2,022.8 $ 4,312.5
Operating income (loss) 906.4 959.8 1,689.5 3,286.1
Net income (loss) ........ (125.4) (50.5) 840.4 761.1
Earnings (loss) per share:
Basic ............... (0.01) (0.01) 0.08 0.06
Diluted ............ (0.01) (0.01) 0.07 0.06
1999
Revenues ................. $ 29.7 91.6 254.3 $ 823.9
Revenue - LOE ............ 20.7 88.7 242.1 766.44
Net income (loss) ........ (714.1) (1,078.2) (1,851.5) (1,740.6)
Earnings (loss) per share:
Basic ............... (0.10) (0.14) (0.21) (0.21)
Diluted ............. (0.10) (0.14) (0.21) (0.21)
For the years ended December 31,
2000 1999 1998
--------------- ------------- --------------
Beginning cash balance $ 1,448,655 $ 198,043 $ 3,985,599
Sources of cash:
Cash provided by operations 3,229,081 (1,262,655) (1,215,673)
Cash provided by financing activities 2,900,170 9,759,960 6,525,108
Cash provided from merger 895,097 - -
--------------- ------------- --------------
Total sources of cash including cash on 8,473,003 8,695,348 9,295,034
hand
Uses of cash:
Oil and gas expenditures (6,666,327) (6,945,695) (8,928,201)
Other assets (including advance to industry partners) (270,490) (300,998) (168,790)
--------------- ------------- --------------
Total uses of cash (6,936,817) (7,246,693) (9,096,991)
--------------- ------------- --------------
Ending cash balance $ 1,536,186 $ 1,448,655 $ 198,043
=============== ============= ==============
For the year ended December 31, 2000, funds on hand and net funds received
from operations and from the exercise of warrants were sufficient to meet our
capital requirements. We received approximately $3,205,000 from the exercise of
warrants. Cash flow from operations increased significantly for the year from
increased production volume and natural gas prices. This will be discussed in
detail in "Comparison of Results of Operations for the Years Ended December 31,
2000 and 1999."
During the year we expended approximately $6.3 million to fund the drilling
of its exploratory prospects, development of existing properties and acquisition
of additional acreage. This included: $2.4 million for the drilling of 13 wells
(9 were completed, 3 were dry holes and 1 is in evaluation process) in our
Jackson County, Texas prospects, $1.0 million on the leasing and drilling of the
Shark Deep prospect in which we went non-consent on the completion, $.5 million
drilling and lease costs related to our Lafourche Parish, Louisiana TC#1 well,
$.5 million for drilling and completion of three wells in the Brookshire Dome
prospect, $.5 million in development and facilities located in the West Cameron
Block 39 and 49 leases, offshore Louisiana, $.3 million in drilling costs
related to our Northern California prospect which were subsequently abandoned
due to depletion, $.6 million in lease acquisition costs on our North Texas
prospect and $.3 million related to development cost in the WEHLU unit in
Oklahoma.
During the year ended December 31, 1999 we realized net proceeds of
$2,835,000 from a bridge note financing, net proceeds of $7,733,553 from public
offering and net proceeds of $2,052,620 from exercise of Beta common stock
warrants. The combination of these proceeds funded our capital requirements for
the year. We issued promissory notes having a maturity date of one year and
bearing an interest rate of 10%. In addition, a total of 459,000 shares of our
common stock were issued in connection with the 1999 bridge financing. Our
bridge notes were repaid in full with accrued interest on July 7, 1999 from the
proceeds of our initial public offering. The estimated fair market value of
429,000 shares of common stock issued in connection with the bridge note of
$2,754,000 was treated as a discount and was amortized over the term of the
promissory note using the interest method. The estimated fair market value of
30,000 additional shares of common stock issued per the terms of the bridge note
of $180,000 was immediately expensed as interest during the year 1999.
Accordingly, we incurred additional interest expense of $2,754,000 because of
the common stock issued in connection with the bridge notes. The debt issuance
costs of the 1999 bridge financing of $89,100 were amortized as additional
interest expense during the year ended 1999.
We financed all of our business activities in December 31, 1998 through
issuances of our common stock in private placements. We raised net proceeds of
$6,548,632 during 1998 from a private placement.
Plan of Operation for 2001
For the year 2001, we expect to fund our capital requirements from existing
working capital, net cash flow from operations (after general and administrative
expense), and the exercise of common stock purchase warrants. We are planning to
raise additional funds through a private placement offering convertible
preferred stock. We expect the private placement to take place early in the
second quarter of 2001.
Our projected 2001 capital expenditures are as follows:
o $8 million for drilling and completion costs associated with our South
Texas and Louisiana prospects
o $2 million associated with drilling, completion and workovers in the
Mid-Continent Region. $1.5 million is for a salt water
disposal well and a redrill project for the WEHLU unit.
o $4 million for the exploration of a prospect located in the Wind River
Basin, Wyoming. We acquired this prospect in the first quarter of 2001
with management reviewing the prospect potential since December 2000
o $1 million for leasehold acquisition and seismic
As with any projection, the timing and amounts can vary. The timing for
drilling wells has been more difficult to estimate due to drilling rig
availability. Generally, funds must be advanced within thirty days or less after
our election to participate.
Our planned capital expenditures and administrative expenses could exceed
those amounts budgeted and could exceed our cash from all sources. Due to the
volatility of the natural gas and crude oil prices, while our capital
expenditures are on budget we could see a significant short fall from cash flow
from operations should these prices decrease. If this happens, it may be
necessary for us to raise additional funds. It is anticipated that additional
funds could be raised from one or more of the following sources:
1) We have approximately 375,725 callable common stock purchase warrants
outstanding exercisable at a price of $7.50 per share. We are able to
call these warrants at any time after our common stock has traded on
Nasdaq at a market price equal to or exceeding $10.00 per share for 10
consecutive days which was achieved in July 2000. It is our intent to
call all of these warrants at such time, if and when, the cash is
needed to fund capital requirements. We will receive proceeds equal to
the exercise price times the number of shares which are issued from the
exercise of warrants net of commission to the broker of record, if any.
We could realize net proceeds of approximately $2,814,500 from the
exercise of all of these warrants. There is no assurance that any
warrants will be exercised or that we will ever realize any proceeds
from the $7.50 warrant calls.
2) We currently have approximately $500,000 of available borrowing
capacity under our revolving credit facility.
3) We may seek mezzanine financing, if available, on terms acceptable to
us. Mezzanine financing usually involves debt with a higher cost of
capital as compared to conventional bank financing. We would seek
mezzanine financing in the range of $1,000,000 to $5,000,000. We would
seek to use this means of financing in the event that a particular
acquisition did not have sufficient proved producing reserve collateral
to support a conventional bank loan.
4) We may realize additional cash flow from oil and gas wells to be
drilled, if found to be productive. We own working interests in wells
that are currently producing and in additional wells, which are
presently being completed and equipped for production. We currently
estimate that during 2001 the wells will generate approximately $16
million of net cash flow after deducting lease operating expenses of
approximately $4 million.
If the above additional sources of cash are insufficient or are unavailable
on terms acceptable to us, we will be compelled to reduce the scope of our
business activities. If we are unable to fund planned expenditures within a
thirty to sixty-day period after a well is proposed for drilling, it may be
necessary to:
1) Forfeit our interest in wells that are proposed to be drilled;
2) Farm-out our interest in proposed wells;
3) Sell a portion of our interest in proposed wells and use the sale
proceeds to fund our participation for a lesser interest;
or
4) Reduce general and administrative expenses.
Our long term goal is to continue the pattern of growing the Company by
accumulating oil and gas reserves through acquisition and drilling during the
next three to five year period, and then selling the Company. In the event we
cannot raise additional capital, or the industry market is unfavorable, we may
have to slow or alter our long-term goal accordingly.
These are forward looking statements that are based on assumptions, which in
the future may not prove to be accurate. Although we believe that the
expectations reflected in such forward looking statements are based on
reasonable assumptions, we can give no assurance that our expectations will be
achieved.
Long Term Liquidity and Capital Resources
The timing of most of our capital expenditures is discretionary. We have no
material long-term commitments associated with our capital expenditure plans or
operating agreements. Consequently, we have a significant degree of flexibility
to adjust the level of such expenditures as circumstances warrant. The level of
capital expenditures will vary in future periods depending on the success we
experience on planned exploratory drilling activities in future periods, gas and
oil price conditions and other related economic factors. Accordingly, we have
not prepared an estimate of capital expenditures for future periods beyond 2001.
Comparison of Results of Operations
Year ended December 31, 2000 and Compared to Year ended December 31, 1999
We have reported net income of $1,425,565 for the year ended December 31,
2000 compared to a net loss of ($5,348,403) for the same period ended 1999. Our
results of operations have been significantly impacted by our ability to
increase production through our exploration activities and acquiring oil and gas
properties. Fluctuations in natural gas and crude oil prices have also
significantly impacted these results.
In Thousands ................................... Years Ended December 31, $ - Increase % - Increase
2000 1999 (Decrease) (Decrease)
- ------------------------------------------------ -------- -------- --------------- -----------
Net income (loss) .............................. $ 1,425.6 $ (5,384.4) $ 6,810.0 126%
Oil and gas sales .............................. 8,037.2 1,199.5 6,837.7 570%
Field service income ........................... 320.6 -- 320.6 100%
Operating expense .............................. 1,516.1 81.5 1,434.6 1760%
G"&"A expense 2,141.0 1,418.2 722.8 51%
Depletion and Depreciation ..................... 2,693.4 914.2 1,779.2 195%
Impairment expense -- 1,225.0 (1,225.0) -100%
Interest expense 393.0 2,966.7 (2,573.7) -87%
Income tax provision ........................... 294.3 -- 294.3 100%
Production:
Natural Gas - Mcf .............................. 1,726.4 475.1 1,251.3 263%
Crude Oil - Bbl ................................ 32.6 1.8 30.8 1711%
Natural Gas Equivalent - Mcfe .................. 1,922.1 486.0 1,436.1 295%
$ per unit:
Ave gas price - Mcf ............................ $ 4.08 $ 2.44 $ 1.64 67%
Ave oil price - Bbl 30.57 23.04 7.53 33%
Ave operating expense - McfEQ .................. .71 0.17 0.54 318%
Ave G"&"A - McfEQ 1.12 2.92 (1.80) -62%
Ave Depl. and Depr. - McfEQ 1.40 1.88 (0.48) -26%
For the twelve months ended December 31, 2000 oil and gas sales increased
$6,837,700 or 570% from the same period ended 1999. A 263% increase in natural
gas production combined with a 67% increase in average natural gas prices
accounted for approximately $5,700,000 of the increase. A 1711% increase in
crude oil production for 2000 and a 33% increase in average 2000 crude oil
prices accounted for the remaining $1,100,000 increase in oil and gas sales. The
increase in natural gas and oil production for 2000 was due to additional wells
drilled and completed during the year and incremental natural gas and crude oil
production acquired in the Merger. Approximately 67% of the increase in our
natural gas production was due to new wells drilled and completed during the
twelve months ended December 31, 2000. Acquired crude oil production accounted
for approximately 88% of the increase in oil production for the year. Higher
natural gas prices for 2000 resulted in approximately $2,800,000 in additional
oil and gas revenues. Generally, we sell our natural gas to various purchasers
on an indexed-based price. These indices are generally affected by the NYMEX -
Henry Hub spot price. We use hedges on a limited basis to lessen the impact of
price volatility. However, fixed pricing from hedges only cover 22% of our
production on an equivalent Mcf basis. Based on our 2000 natural gas production,
a change in the average natural gas price realized by the Company of $1.00 per
Mcf would have resulted in an approximate $1.5 million reduction in net income
before income taxes.
Operating expenses, including production and ad valorem taxes, increased
approximately $1,434,600, or 1760%, to $1,516,100 for the year ended 2000. The
increased expenses were due to approximately $1,000,000 of additional operating
expenses associated with the Merger properties, which included a gathering
system, and the increase in number of wells put on production for the year. The
average operating expense for the Merger oil and gas wells was $1.51 per
equivalent Mcf for the period September 1, 2000 through December 31, 2000. This
operating cost per equivalent Mcf is significantly higher than the average for
the remaining properties of $.33 per equivalent Mcf due to the Merger properties
being older in production life and the necessity to dispose of a significant
volume of salt water produced. Additionally, due to the age of the properties
repair and maintenance costs are higher than that of the other properties.
G"&"A expenses for the twelve months ended December 31, 2000 increased
in absolute dollars by approximately $722,800 but decreased $1.80 on a per
equivalent Mcf basis from the same period in 1999. The following shows the major
items accounting for the 2000 increase:
o Relocation and severance expense associated with our corporate office
move from Newport Beach, CA to Tulsa, OK of $289,000 which included a
non-cash charge of $128,000 associated with the vesting rights on stock
warrants of a former officer/employee
o Incremental increase in costs associated with additional employees
hired from the Merger, which was approximately $261,000 for the
four-month period September 2000 through December 2000
o Fees of approximately $124,000 associated with our entry on NASDAQ's
National Market system
o Overall increase in corporate expenses of approximately $120,000 due to
increased level of activity from our growth.
Depletion and depreciation expense increased $1,779,200, or 195%, to
$2,693,439 for 2000 from $914,233 in 1999 due to increase production volume in
2000. Our average depletion and depreciation rate per equivalent Mcf for 2000
decreased 26% to $1.40 from $1.88 in 1999 primarily as a result of the reserves
acquired in the Merger and those reserves discovered from our exploration effort
during the year.
There was no impairment expense for the twelve-month period ended December
31, 2000 due to the determination of the total evaluated costs in both the U.S.
and foreign cost pools exceeding their net realizable value. In 1999, it was
determined that the total costs in the U.S. evaluated properties cost pool
exceeded their present value and accordingly an impairment write-down of
$1,167,910 was recorded. The impairment was due mainly to downward revisions of
reserve estimates associated with two wells drilled in 1998. The downward
revisions were due to disappointing production results from the wells in the
fourth quarter of 1999 when producing zones in the wells commenced significant
production of salt water in place of gas and oil. Additionally, a $57,052
impairment charge was recorded for our evaluated cost associated with our
Australian properties.
Interest expense decreased for the year ended December 31, 2000 compared to
the same period for 1999 primarily due to the retirement of our bridge notes,
which were retired in July 1999. Interest expense related to the bridge notes
for 1999 consisted of the following:
Cash interest expense $ 120,555
Amortization of note discount and fair market value of 459,000 shares 2,754,000
Amortization of deferred loan costs 89,100
---------------
Bridge note interest expense for the year ended December 31, 1999 $ 2,963,655
===============
The decrease was partially offset by the interest expense we incurred in
2000 as a result of debt acquired in the Merger.
Year Ended December 31, 1999 and Compared to Year Ended December 31, 1998
Net loss for the year ended December 31, 1999 was $(5,384,403) compared to
$(2,384,500) for the year ended December 31, 1998. The increase in net loss was
primarily due to the interest expense related to the bridge note.
Loss from operations totaled $(2,439,493) for the year ended December 31,
1999 compared to $(2,429,343) for the year ended December 31, 1998.
During the year ended December 31, 1999 we had oil and gas revenues of
$1,199,480. Our net production was 475,065 mcf at an average price of $2.44 per
mcf and 1,822 barrels of oil at an average price of $23.03 per barrel. During
the year ended December 31, 1998 we generated no revenues.
During the year ended December 31, 1999 we incurred lease operating
expenses of $81,538. Our average lifting cost for this period was $.17 per mcf
equivalent. During the year ended December 31, 1998 we incurred no lease
operating expense.
General and administrative expenses for the year ended December 31, 1999
were $1,418,240 compared to $746,769 for the year ended December 31, 1998. This
represents a $671,471 or a 90% increase over the prior year period. The primary
reasons for the increase were due to:
o An increase in operational activities in 1999 versus 1998;
o An increase in the number of employees from five in 1998 to six in 1999; and
o General and administrative costs incurred in 1999 related to our
initial public offering and registration statement which are not
readily identifiable as offering costs.
1998 1999 Total
---- ---- -----
Foreign cost pool $ 1,624,218 $ 57,052 $ 1,681,270
U.S. cost pool 46,473 1,167,910 1,214,383
------------- ------------ -------------
$ 1,670,691 $ 1,224,962 $ 2,895,653
============= ============ =============
As of December 31, 1999, it was determined that the total costs in the U.S.
evaluated properties cost pool exceeded the full cost ceiling limitation.
Accordingly, an impairment write-down of $1,167,910 was recorded for the year
ended December 31, 1999. The impairment was due mainly to downward revisions of
reserve estimates associated with two wells drilled in 1998. The downward
revisions were due to disappointing production results from the wells
experienced in the fourth quarter of 1999 when the producing zones in the wells
began producing large amounts of water in place of gas and oil.
Depreciation and depletion expense for the year ended December 31, 1999 was
$914,233 compared to $11,883 for the year ended December 31, 1998. This
represents a $902,350 increase over the prior year period. The primary reason
for the increase is due to the fact Beta had no oil or gas production in the
prior year period that would give rise to depletion expense.
Other income for the year ended December 31, 1999 consisted of interest
income in the amount of $21,741. Beta realized $44,843 of interest income for
the year 1998. The reason for the decrease was lower average cash and cash
equivalents balances for the 1999 period as compared to the 1998 period.
During the year ended December 31, 1999, Beta incurred interest expense of
$2,966,651, substantially all of which related to the bridge notes. Interest
expense related to the bridge notes for the 1999 period consists of the
following:
Cash interest expense $ 120,555
Amortization of note discount and fair market value of 459,000 shares 2,754,000
Amortization of deferred loan costs 89,100
---------------
Bridge note interest expense for the year ended December 31, 1999 $ 2,963,655
===============
During the year ended December 31, 1998, Beta incurred no interest expense.
Quarter Ended December 31, 2000 and Compared to Quarter Ended September 30, 2000
(Unaudited)
Revenues and operating income for the quarter ended December 31, 2000
increased approximately 113% and 94%, respectively, compared to the quarter
ended September 30, 2000. The increases were a result of increased production
volumes associated with the RRE merger, which was effective September 1, 2000
and additional wells put on production. Our production volume for the quarter
ended December 31, 2000 was approximately 803,000 Mcf equivalent compared to
approximately 458,800 Mcf equivalent or 75% increase.
Net income for the fourth quarter ended 2000 decreased by approximately 9%
from the previous quarter primarily due to increased depletion and depreciation
expense, interest expense and income tax expense. Depletion and depreciation
expensed for the quarter increased approximately $1.0 million from the quarter
ended September 30, 2000 to $1.4 million. Interest expense increased
approximately $.3 million from the previous quarter due to RRE outstanding debt.
Income tax expense for the quarter ended December 31, 2000 was approximately $.3
million higher than the quarter ended September 30, 2000.
Quarter Ended December 31, 2000 and Compared to Quarter Ended December 31, 1999
(Unaudited)
Revenues for the quarter ended December 31, 2000 increased by approximately
$3.5 million from December 31, 1999 to $4.3 million. Operating and net income
for the quarter ended December 31, 2000 increased approximately $2.5 million
from December 31, 1999 to $3.3 million and $.8 million, respectively. The
increases were a result of increased production volumes associated with the RRE
merger, which was effective September 1, 2000 and additional wells put on
production in 2000.
The results for quarter ended December 31, 1999 included an impairment
charge for approximately $1.2 million due to downward revisions of reserves
associated with wells drilled in 1998. Depletion and depreciation expense for
quarter ended December 31, 2000 was approximately $.6 million greater than
quarter ended December 31, 2000. The quarter ended December 31, 2000 had
interest expense of approximately $.3 million and income tax expense of
approximately $.3 million while there was no comparable expense for the same
quarter in 1999. Collectively, the increased depreciation and depletion expense,
interest expense and income tax expense for the quarter ended December 31, 2000
offset the impairment charge as previously mentioned for December 1999.
Income Taxes
As of December 31, 2000, we had available, to reduce future taxable income,
a tax net operating loss carryforward of approximately $11,624,000, which
expires in the years 2013 through 2020. Utilization of the tax net operating
loss carryforward may be limited in the event a 50% or more change of ownership
occurs within a three-year period. The tax net operating loss carryforward may
be limited by other factors as well. As of December 31, 2000, we have a deferred
liability of approximately $3,526,304.
Impact of Recently Issued Standards
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 (FASB133), "Accounting for Derivative
Instruments and Hedging Activities." The FASB has subsequently issued Statement
No. 137 and Statement No. 138 which are amendments to FASB133. FASB133, as
amended, requires that an entity recognize all derivatives as assets or
liabilities in the statement of financial position and measure those instruments
at fair value. FASB133, as amended, is effective for fiscal years beginning
after June 15, 2000. FASB133, as amended, cannot be applied retroactively and
must be applied to (a) derivative instruments and (b) certain derivative
instruments embedded in hybrid contracts. We adopted SFAS133, as amended,
beginning January 1, 2001. We do not believe the adoption of FASB133 will have a
material impact on our financial position or results of operation.
Item 7A. Quantitative and Qualitative Disclosure About Market Risk
We are exposed to market risk related to adverse changes in oil and gas
prices. Our oil and gas revenues can be significantly affected by volatile oil
and gas prices. This volatility can be mitigated through the use of oil and gas
derivative financial hedging instruments. Currently, we have derivative
financial instruments in place to mitigate the fluctuations in gas price. The
hedged volume represents approximately 22% of our gas equivalent production and
is hedged until July 2001. Another 10% of our gas equivalent production was
committed to a twelve-month fixed price contract, which was in effect until July
2001. However, in October 2000, we ceased deliveries to the purchaser due to the
non-performance of payment. No further deliveries have been made under this
contract and said contract is currently in litigation. (See Item 3. Legal
Proceedings.) The remainder of our production is not hedged and we may continue
to experience wide fluctuations in oil and gas revenues as a result. We are also
exposed to market risk related to adverse changes in interest rates. This
volatility could be mitigated through the use of financial derivative
instruments. Currently, we do not have any derivative financial instruments in
place to mitigate this potential risk.
Item 8. Financial Statements and Supplementary Data.
Our financial statements and supplementary financial data, which begin on
page F-1, are included elsewhere in this report.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
Director
Name Age Since Position
Steve Antry 45 1997 President, Chairman of the Board, Director
R. Thomas Fetters 61 1997 Managing Director of Exploration, Director
Joe C. Richardson, Jr. 73 1997 Director
John P. Tatum 66 1999 Director
Robert C. Stone, Jr. 51 2000 Director
Joseph L. Burnett 48 Chief Financial Officer since 2000
Stephen L. Fischer 41 Vice President of Capital Markets since 1997
Virginia Cherry 55 Secretary since 2000
Lisa Antry 38 Treasurer since 1997
Directors are elected to serve until the next annual meeting of
stockholders and until their successors have been elected and qualified. The
Bylaws permit the board itself to fill vacancies and appoint additional
directors pending shareholder approval at the next annual meeting. Officers are
appointed to serve until the meeting of the Board of Directors following the
next annual meeting of stockholders and until their successors have been elected
and qualified. Beta's Bylaws currently authorize six directors to serve on the
Board of Directors. The last annual meeting of shareholders was held on June 24,
2000.
Steve Antry and Lisa Antry are married.
The business experience of each director, executive officer and key
employee is summarized below.
Steve A. Antry, President and Chairman of the Board of Directors, is Beta's
founder. In addition, Mr. Antry founded Beta Capital Group, Inc., a financial
consulting firm in November 1992, and was its President through June 1997. Beta
Capital Group, Inc. specializes in selecting and working with emerging oil and
gas exploration companies which have production and drilling prospects strategic
for rapid growth yet also need capital and market support to achieve that
growth. Most recently, Mr. Antry orchestrated and helped to implement the
restructuring of Pease Oil and Gas Company, NASDAQ: WPOG, and remains a
Director. Mr. Antry remains Chairman of the Board of Directors of Beta Capital
Group, Inc., but resigned as its President to devote his full attention to Beta.
Before forming Beta Capital Group, Inc., Mr. Antry was an early officer of
Benton Oil "&" Gas Company, NYSE: BNO, from 1989 through 1992, ultimately becoming
President of a wholly owned subsidiary. Before Benton, Mr. Antry was a Marketing
Director for Swift Energy, NYSE: SFY, from 1987 through 1989. Mr. Antry began
working in the oil fields in Oklahoma in 1974. He has served in various
exploration management capacities with different companies, including Warren
Drilling Company, as Vice President of Exploration and Nerco Oil and Gas, a
division of Pacific Power and Light, where he served as Western Regional Land
Manager. Mr. Antry is a member of the International Petroleum Association of
America "IPAA", serving on the Capital Markets Committee and has B.B.A. and
M.B.A. degrees from Texas Christian University.
R. Thomas Fetters, Managing Director of Exploration, and Director, spent 17
years with Exxon ultimately achieving the position of Exploration Planning
Manager, Exxon U.S.A. Other notable positions held include Exploration Manager
for Exxon Australia "ESSO" and Division Manager of Research in Houston and Chief
Geologist, Exxon Production Malaysia. Mr. Fetters was President and Chief
Executive Officer of CNG Producing Co. in New Orleans from 1983 through 1989 and
President of XCL-China, Ltd. from 1989 through 1995. From 1995 through 1997, he
served as Senior Vice President of National Energy Group and also currently sits
on the Board of XCL, Ltd.. He earned his B.S./M.S. in Geology from the
University of Tennessee in 1966.
Joe C. Richardson, Jr., Director, graduated from Texas A"&"M with B.S. degrees in
Petroleum Engineering and Mechanical Engineering in 1950 when he started his
career with Shamrock Oil and Gas in Amarillo, Texas. In 1961, Mr. Richardson
formed an oil, gas, refining, and compressor equipment fabrication company and,
in 1968, co-founded a public oil and gas company that was later merged with
Worldwide Energy, Inc. Mr. Richardson has been an officer and/or director of
several successful public and private companies including Pyro Energy, Inc.
(NYSE), Consolidated Oil "&"Gas (AMEX), Texoil, Inc. (NASDAQ), and Corporate
Systems Corporation. He is a Regent Emeritus of the Texas A"&"M University System,
past President of the Texas A"&"M Twelfth Man Association, and was honored in 1989
with the University's Distinguished Alumni Award. He currently serves on the
University Presidents' Advisory Board and the Engineering Advisory Council. Mr.
Richardson is a registered engineer in the state of Texas. The Petroleum
Engineering Building on the campus of Texas A"&"M University, completed in 1990,
was named in his honor.
John P. Tatum, Director, joined Beta as a director in March 1999. Mr. Tatum has
worked in the oil and gas industry since 1962, holding successive positions with
Skelly Oil Company, Placid Oil Company, Hunt International Company and Hunt
Energy Company. From 1980 to 1996, Mr. Tatum was employed with Triton Energy
Corporation as Vice President (1980-82), Senior Vice President (1982-1991) and
Executive Vice President (1991-96). As Senior Vice President for Triton Energy
Corporation, Mr. Tatum was responsible for directing Triton's operations in
Colombia, Thailand, New Zealand, Nepal, Gabor, Cote D'Ivoire and Argentina.
Since 1996, Mr. Tatum has worked as an international oil "&" gas consultant.
Mr. Tatum received his B.B.A. from the University of Texas in 1956 and conducted
graduate studies at the Louisiana State University Graduate Business School.
Robert C. Stone, Jr., Director, joined Beta in September 2000. Mr. Stone's last
five years of employment were as Manager of Technical Services, Energy Division,
First National Bank of Commerce from 1994 to 1998 (he started with First
National as an engineer in 1983) and Manager of Energy Technical Services,
Energy/Maritime Division, Hibernia National Bank from 1998 to this year which
included evaluation responsibilities for all syndicated and direct lending
E"&"P segment clients. Specifically, Mr. Stone concluded or approved all oil
and gas collateral evaluations, and developed industry client relationships as
well as pricing lending policies. Currently Mr. Stone is the Senior Vice
President/Manager of the Energy Group at Whitney National Bank in New Orleans,
Louisiana. Mr. Stone began his career as an engineer for approximately eight
years with Exxon Company, U.S.A. Mr. Stone holds both a B.S. and M.S. in
Engineering from the University of Houston. He was also a Founding Governor of
the City Energy Club of New Orleans and is involved with many civic
organizations in New Orleans where he still resides.
Joseph L. Burnett, Chief Financial Officer, joined Beta in June 2000. He comes
to Beta with 26 years of oil and gas accounting experience and is a CPA. Most
recently, Mr. Burnett served American Central Gas Technologies, Inc. as
Controller for approximately six years. Prior to American Central, Mr. Burnett
served at Esco Energ;y for approximately seven years as Controller and Vice
President. Mr. Burnett started his oil and gas career at Skelly Oil (later Getty
Oil) in 1974. Mr. Burnett received his Bachelor of Science in Business
Administration from Oklahoma State University in 1974.
S