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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 fiscal 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
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Commission File Number 0-14334
VENUS EXPLORATION, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 13-3299127
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1250 N.E. LOOP 410, SUITE 1000, SAN ANTONIO, TX 78209
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code (210) 930-4900
Securities registered pursuant
to Section 12(b) of the Act: None
Securities registered pursuant
to Section 12(g) of the Act: Common Stock, $0.01 par value
(Title of Class)
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 twelve months, and (2) has been subject to such filing
requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in the definitive proxy statement
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the Common Stock held by non-affiliates of the
Registrant (all directors, officers and holders of five percent or more of the
Common Stock of the Company are presumed to be affiliates for purposes of this
calculation), computed by reference to the closing bid price of such stock on
March 19, 2001, was approximately $4,300,000. As of March 19, 2001, the
Registrant had outstanding 12,343,196 shares of Common Stock.
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DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Annual Report on Form 10-K will be
included in the Registrant's definitive Proxy Statement for its 2001 Annual
Shareholder Meeting. It is expected that the Proxy Statement will be filed with
the Commission not later than April 30, 2001.
TABLE OF CONTENTS
PART I....................................................................................................................3
ITEM 1. BUSINESS.....................................................................................................3
ITEM 2. PROPERTIES..................................................................................................15
ITEM 3. LEGAL PROCEEDINGS...........................................................................................19
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........................................................19
PART II..................................................................................................................20
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS...................................20
ITEM 6. SELECTED FINANCIAL DATA.....................................................................................21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.......................21
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..................................................27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................................27
ITEM 9. CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE......................27
PART III.................................................................................................................28
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................................28
ITEM 11. EXECUTIVE COMPENSATION......................................................................................28
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..............................................28
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................................28
PART IV..................................................................................................................28
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES...................................................................28
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PART I
ITEM 1. BUSINESS
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. Those statements are contained under this Item
1 "-Business," under Item 7 "-Management's Discussion and Analysis of Financial
Condition and Results of Operations," and elsewhere in this Form 10-K. The
forward-looking statements are identified by language that speaks of future
events. For example, words such as "may," "could," "believe," "expect,"
"intend," "anticipate," "estimate," "target," "continue," "projected," "future,"
"will," "seek," and "plan". The forward-looking statements address such matters
as geological estimates of oil and gas reserves, exploratory and development
drilling plans and schedules, capital expenditures, availability of capital
resources, financial projections, present values of future production, financing
assumptions and other statements that are not historical facts. Although
statements involving those matters are based on information available at the
time this Annual Report on Form 10-K was prepared and although Venus believes
that its statements are based on reasonable assumptions, it can give no
assurance that its goals will be achieved or that the level of production or
financial return expected can be achieved. Some of the important factors that
could cause actual results to differ materially from those predicted in the
forward-looking statements include (i) state and federal regulatory developments
and statutory changes, (ii) the timing and extent of changes in commodity prices
and markets, (iii) the timing and extent of success in acquiring leasehold
interests and in discovering, developing or acquiring oil and gas reserves, (iv)
the conditions of the capital and equity markets during the periods covered by
the forward-looking statements, (v) reliance on estimates of reserves, (vi)
drilling results, (vii) the Company's success in raising additional capital to
fund its operations and to fund the execution of its strategy, and (viii) other
matters beyond the control of the Company; e.g., the risk factors that are
listed beginning on page 6.
COMPANY OVERVIEW
Venus Exploration, Inc. ("Venus" or the "Company") is an independent oil and gas
exploration and development company. We acquire producing oil and gas properties
onshore in the United States and apply advanced geoscience technology to the
exploration for and exploitation of undiscovered reserves. The Company presently
has oil and gas properties, acreage and production in eight states, including
Texas, Louisiana, Oklahoma and Utah. Our current focus is:
o the Expanded Yegua Trend of the Upper Texas and Louisiana Gulf Coast, and
o the Cotton Valley Trend of East Texas and Western Louisiana.
Oil and gas terms and abbreviations that are used in this Annual Report on Form
10-K are defined in this Item 1 under "Business - Definition of Certain Oil and
Gas Terms, beginning on page 13. Those terms and abbreviations are usually
capitalized in the text.
Proved Reserves as of December 31, 2000, totaled 10.8 Bcfe, a decrease of .3
Bcfe from the 11.1 Bcfe that we reported at year-end 1999, a 2.7% decrease. The
decrease is due to the downward revision of reserves of some existing properties
and by normal production. Production for 2000 totaled .9 Bcfe and new
discoveries, extensions and revisions of reserves on our existing properties
totaled .5 Bcfe. In 2000, average daily net production increased to 2,400
Mcfe/day from 2,250 Mcfe/day in 1999, a 6.7% increase. The increase is due to
increased production on existing wells and the completion of a new well. As of
December 31, 2000, approximately 47% of our reserves are natural gas reserves.
As of December 31, 1999, approximately 39% of our reserves were natural gas.
Venus operates 47% of its Net Wells.
BUSINESS STRATEGY
Venus's strategy consists of:
o Exploration for oil and natural gas reserves in geographic areas where the
Company has expertise
o Exploitation and development drilling in existing oil and gas fields
o Acquisition of strategic producing properties with upside potential
Exploration - We use advanced geoscience technology to conduct exploration
programs for new oil and gas reserves and undiscovered fields in geological
trends that are considered to contain an undiscovered resource base of oil and
natural gas. High-risk exploration gives us the opportunity to participate in
discovery of substantial oil and gas reserves and the resultant
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rapid growth in asset values that can occur. Because of the inherent uncertainty
and high financial risk associated with the outcome of individual drilling
prospects, we maintain an inventory of many exploratory Prospect Leads from
which drilling prospects are confirmed and generated. We attempt to reduce our
financial risk and to obtain financing for a large portion of the exploration
costs through sale to oil and gas industry co-venturers of working interests in
prospects originated by us. Our management has used this strategy successfully
in the past. Due to the decline in oil prices between 1997 and 1999, capital
available for exploration budgets was reduced during that period, both for the
oil and gas industry in general and for Venus specifically. As a result, Venus
reduced exploration activity and continue to work only selected prospects
believed to have extraordinary merit.
Our exploration team currently concentrates on two geographic areas: the
Expanded Yegua Trend of the Upper Texas and Louisiana Gulf Coast and the Cotton
Valley Trend of East Texas and Western Louisiana. Secondary areas are the South
Midland Basin and the mid-continent. We have an inventory of exploration
Prospects and Prospect Leads, and we are reactivating exploratory drilling
projects so that when, and if, industry drilling budgets are restored for
exploration, we will have drilling projects available in which to offer
participation to industry co-venturers. The primary geoscience technologies we
use to evaluate Prospects and Prospect Leads are 2-D and 3-D seismic surveys and
the subsurface geological studies used to interpret the data gathered by these
seismic surveys. Our in-house technical capability is an important ingredient in
our current and continuing ability to conduct comprehensive exploration programs
and ongoing exploitation of existing fields.
Exploitation - We use advanced geoscience technology to exploit and to develop
oil and gas reserves in currently producing fields which we believe are not
fully developed. We are conducting active exploitation and development
activities in seven different fields in Texas, Oklahoma and Utah. Our working
interest in those fields varies from 2.5% to 100%, and we operate in four of the
seven active fields. During periods of low commodity prices, we emphasize
acquisition and expansion of reserves in existing oil and gas fields rather than
exploration for new reserves in unestablished areas.
Acquisition - We seek strategic producing property acquisitions that offer
near-term production enhancement potential and longer-term development drilling
potential. These opportunities on properties we may potentially acquire can be
investigated through the application of advanced technology by our technical
team. We also seek to accomplish strategic acquisitions of producing assets with
development and exploratory potential through strategic alliances with other oil
and gas companies. We may also sell non-strategic properties as a part of our
effort to concentrate on our focus areas.
COMPANY HISTORY
We were incorporated in the State of Delaware in September 1985 under the name
Xplor Corporation. In 1997, through a reverse merger, the present management
team was put into place, implementing our current exploration and development
focus. After that merger and change of management, we changed our name to Venus
Exploration, Inc. We are a public entity traded on the Nasdaq SmallCap
Market(SM) under the symbol VENX. Members of our management team have been
responsible for the discovery, development and exploitation of relatively
significant reserves of oil and gas for privately held predecessor companies
over the last 30 years.
During the period between 1997 and 1999, our financial situation deteriorated in
large part due to a downturn in oil and gas prices, a lack of cash flow and an
inability to raise capital to finance new drilling projects or acquisitions of
oil and gas properties. To address our financial condition, including our
failure to comply with some covenants of our credit facility and our lack of
liquidity in late 1998 and 1999, our management developed and implemented a
restructuring plan. The following steps were implemented:
o selling non-core properties
o reducing office personnel
o concentrating on development projects that have a lower degree of
geological and engineering risk relative to the economic investment and
anticipated rate of return
o using our technical expertise and our network of contacts in the
industry to acquire attractive packages of oil and gas properties that
are already producing and that have undrilled potential
o raising equity capital
RECENT DEVELOPMENTS
Below is an update of significant developments during 2000.
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Conversion to Common Stock - We converted $1,000,000 original principal
amount of notes into 1,142,854 shares of our common stock. We issued an
aggregate of 63,053 shares of our common stock in payment of the interest that
became due on the notes due or accrued during 2000. These shares were issued in
lieu of cash interest payments accrued of $37,858 through August 22, 2000, the
date of the last conversion. The shares were issued pursuant to an exemption
from registration under the Securities Act of 1933, as amended; therefore the
shares are restricted.
Repayment of bank debt - In December of 1999, we completed the sale of
some oil and gas properties that were held through a joint venture, EXUS Energy,
with another industry participant. On January 6, 2000, we used $7.1 million of
the net proceeds from the sale of the EXUS Properties to repay our share of the
EXUS Energy bank debt under a credit facility with NationsBank, $7 million to
repay our convertible note to the other joint venturer, $250,000 to satisfy a
prepayment penalty under that convertible note, and $3.7 million to reduce our
then existing bank debt. The balance of our bank debt, $152,000, was paid on
March 30, 2000.
Nasdaq Listing - On January 28, 2000 Nasdaq removed the conditional
status of our Nasdaq listing that arose in 1999 from our temporary inability to
comply with all of Nasdaq's continued listing requirements. On July 17, 2000,
Nasdaq sent us a letter stating that our minimum bid price had not been at least
$1.00 over the preceding 30 consecutive trading days as required under
Marketplace Rule 4310(c)(4). Failure to comply with this rule constitutes
grounds for delisting; however, the rule provides an automatic 90 day period for
our bid price to exceed $1.00 for at least 10 consecutive trading days, at which
time, Nasdaq's staff would determine if we were in compliance with the rule. The
rule also sets out an appellate process which includes a hearing. On October 12,
2000, we requested a hearing in order to appeal the matter and, on October 13,
2000, Nasdaq granted us a hearing on November 9, 2000. Beginning, October 4,
2000, our closing bid price exceeded $1.00 for a period that exceeded the 10
consecutive trading day minimum and, on November 2, 2000, we received a letter
from Nasdaq stating that we were in compliance with Nasdaq Marketplace Rule
4310(c)(4) and the November 9, 2000 hearing was cancelled as it was no longer
necessary. We have continued to be in compliance with the rule since that date.
Current Credit Facility - On May 5, 2000, we entered into a loan
agreement with a new primary lender establishing a one year, $15 million
revolving line of credit subject to a borrowing base that will be redetermined
by the lender every six months (October 1 and April 1), based on our oil and gas
reserves. The initial borrowing base was $2.45 million and, by the terms of the
loan agreement, such borrowing base has declined at the rate of $50,000 per
month. On October 1, 2000, the lender determined the borrowing base was $2.2
million, which base continued to decline at $50,000 per month until the next
borrowing base redetermination on April 1, 2001, at which time, our lender
determined our borrowing base to be $1,130,000. We may request interim
redeterminations; however, changes in the borrowing base are solely at the
discretion of the lender based on the lender's then current engineering
standards and are subject to the lender's credit approval process. Mandatory
prepayment is required to the extent outstanding amounts under the credit
facility exceed the borrowing base. Outstanding balances under the facility bear
interest at the lender's prime rate plus 1%. The loan agreement terminates on
May 8, 2001. Although we intend to refinance the outstanding balance, to date,
we have not obtained a commitment from a lender for such a refinancing.
Gain on Sale of Other Asset - During the first quarter 2000 we sold an
asset classified as other assets on our financial statements for $253,000. We
recorded a gain of approximately $199,000 during the first quarter 2000 related
to the sale of the asset.
Management Changes - During the third quarter 2000, Patrick Garcia, our
previous Chief Financial Officer, resigned his positions with us to pursue other
business opportunities. On October 31, 2000, P. Mark Stark joined us in a
management capacity and on December 12, 2000, Mr. Stark was named Chief
Financial Officer. In addition, Terry Hardeman, who had held several positions
with us and our predecessors was named Chief Accounting Officer.
Stock Repurchase Plan - Effective September 18, 2000, the Executive
Committee of the Board of Directors approved a plan for the repurchase of up to
300,000 shares of our common stock. With the consent and approval of our lender
under our credit facility, we have the authority to purchase $100,000 worth of
our common stock in open market transactions at prices related to the
independent market for common stock, all in accordance with the terms and
provisions of Rule 10b-18 ("Rule 10b-18") under the Securities and Exchange Act
of 1934, as amended. Unless renewed by action of the Board of Directors, the
repurchase plan, as amended, shall terminate on the earlier of the purchase of
the 300,000 shares or June 15, 2001.
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Restoration of Salary Levels - On or about March 31, 2000, salaries
that were reduced as a part of our restructuring plan initiated in 1998 were
increased to their previous levels.
Successful Completion of the #1 Apache Gas Unit Well - We successfully
completed a development well in Jefferson County, Texas, in the Constitution
Field the #1 Apache Gas Unit in the Westbury Middle Yegua Sand. The well began
producing on October 2, 2000, at an initial production rate of 3.682 million
cubic feet of gas per day (Mmcfd) and 312 barrels of condensate per day, with
168 barrels of water per day flowing through 15/64 inch choke with 3,870 #psi
flowing tubing pressure. We have a 15% Working Interest.
Increase in the Number of Authorized Shares - At our 2000 Annual
Meeting, our shareholders approved an amendment to the Certificate of
Incorporation that increased the number of authorized shares of common stock
from 30,000,000 to 50,000,000 shares.
RISK FACTORS
Lack of Liquidity - Our assets are predominately real property rights
and intellectual information that we developed regarding our properties and
other geographical areas that we are studying for exploration and development.
The market for these types of properties fluctuates and can be very small.
Therefore, our assets can be very illiquid and not easily converted to cash.
Even if a sale can be arranged, the price may be significantly less than levels
that management believes the properties are worth. That lack of liquidity can
have materially adverse effect on our strategic plans, normal operations and
credit facilities.
Lack of Profitable Operations - Since commencing operations in 1996, we
have not reported operating profits. We incurred net losses of approximately
$2,007,000 for the year ended December 31, 1996, $4,168,000 for the year ended
December 31, 1997, and $8,670,000 for the year ended December 31, 1998. Although
we reported net income of $1,010,000 for 1999, that was a result of reporting a
$4.8 million pre-tax gain from the sale of properties. In 1999, we reported a $3
million operating loss, and in 2000 the operating loss was $1.5 million.
We may never generate sufficient revenues to achieve profitability, excluding
gains that we may report from sales of assets. Even if we attain profitability,
we may not sustain or increase profitability on a quarterly or annual basis in
the future. At December 31, 2000, we had an accumulated deficit of approximately
$16.7 million.
Non-Traditional Financing to Fund Business Plan - We may use
non-traditional sources of financing to acquire properties or to fund our
capital expenditures, including the costs of drilling wells. For example, if we
find unencumbered properties to buy, we may use financing that is secured only
by those properties and the oil and gas production from those properties. In an
arrangement like that, the lender will have no recourse against our other
assets, and the prospective lender may require us to pay a higher rate of
interest on the indebtedness.
In addition, we may issue short-term or bridge financing, including
indebtedness, or issue preferred stock or other securities in order to raise
capital. Given our recent financial condition, if we issue these securities, the
purchaser may require us to pay a premium or to agree to more onerous conversion
or other terms.
Volatility of Oil and Gas Prices - Historically, the market prices for
oil and gas have been volatile, and they are likely to continue to be volatile
in the future. We sell most of our oil and gas at current market prices rather
than through fixed-price contracts. Thus, volatility in market prices can
jeopardize our financial condition, operating results and future growth. Sharply
reduced oil and gas prices during 1998 and early 1999 negatively impacted our
results of operations, our access to capital, and the estimated value of our oil
and gas reserves. This drop in prices also increased our operating losses. The
price volatility is the result of factors beyond our control including:
o domestic and foreign political conditions,
o the overall supply of and demand for oil and gas,
o the price of imports of oil and gas,
o weather conditions,
o the price and availability of alternative fuels,
o overall economic conditions,
o exploration and drilling costs,
o pipeline availability and transportation costs, and
o federal and state regulatory and statutory developments.
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On a pro forma basis for the twelve months ended December 31, 2000, taking into
account the sales of non-core properties, our 2000 production was 68% crude oil
and condensate; however, our earnings and cash flow are sensitive to
fluctuations in both oil and gas prices. Excluding production from properties
sold during 2000, a $0.10 per Mcf change in average gas prices would have
resulted in approximately a $31,000 difference in gross revenues for the twelve
months ended December 31, 2000. Also on a pro forma basis, a $1.00 per Bbl
change in average oil prices would have resulted in approximately a $95,000
difference in gross revenue for the twelve months ended December 31, 2000.
Debt Financing - We plan to incur significant indebtedness as we
execute our exploration, exploitation and acquisition strategy. A high debt
structure may require us to pursue non-traditional and more expensive financing.
The higher level of indebtedness that we may incur will have several important
effects on our future operations, including:
o a substantial portion of cash flow from operations will be used to pay
interest on the outstanding debt and will not be available for other
purposes,
o our bank credit agreement will likely limit the uses of capital,
o our ability to obtain additional financing in the future may be
impaired,
o since the interest on our indebtedness likely will be calculated with a
variable rate, increases in that rate could further decrease our
liquidity, and
o our lender may require us to hedge production prices, which could result
in a loss of revenues from potential increases in product prices paid
for our oil and gas production.
Replacement and Expansion of Reserves - Our financial condition and
results of operations depend substantially upon our ability to find or acquire
additional oil and gas reserves that are economically viable and to successfully
develop those reserves. If we are unable to do so, our proved reserves will
usually decline as those reserves are produced. As used in this annual report,
the term "proved reserves" means the estimated quantities of oil and gas that
the geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions and current regulatory practices.
Our value is directly related to our level of reserves. We must replace our
reserves, even during periods of low oil and gas prices when it is difficult to
raise the capital necessary to finance acquisitions or development. Without
successful exploration, development or acquisition activities, our reserves,
production and revenues will decline rapidly. We may not be able to find or
acquire new reserves or to profitably develop and produce new reserves.
Exploration Risks - Our business strategy focuses in part on adding
reserves through exploration, where the risks are greater than in acquisitions
and development drilling. By definition, exploration involves operations in
areas about which little is known. We use 3-D seismic data and other advanced
technologies to identify possible new reserve locations and to reduce our
exploration risk, but exploratory drilling remains speculative. Even when
extensively used and properly interpreted, 3-D seismic data and other similar
visualization techniques only assist geoscientists in identifying subsurface
structures and hydrocarbon indicators. These techniques do not conclusively
allow an interpreter to know if hydrocarbons in the form of oil or gas are
present or are economically producible. The use of 3-D seismic data and other
technologies also requires greater pre-drilling expenditures than traditional
drilling strategies. We could incur losses as a result of these higher
expenditures. We, likewise, may fail to increase our reserves through
exploration.
Acquisition Risks - Part of our business plan is to acquire properties
already producing oil and gas and to increase the reserves attributable to those
properties through development drilling. The successful acquisition of producing
properties requires an assessment of recoverable reserves, future oil and gas
prices, operating costs and potential environmental and contractual liabilities.
Our assessment, however, will not reveal all existing or potential problems, nor
will it permit us to become sufficiently familiar with the properties to fully
assess their deficiencies and capabilities. We do not perform inspections on
every well or pipeline, and structural and environmental problems are not
necessarily observable even when an inspection is undertaken. Even when problems
are identified, the seller may not be willing, or financially able, to give
contractual protection against the problems, and the decision may be made to
assume environmental and other liabilities in connection with acquired
properties. After a property is acquired, environmental liabilities may be
discovered that may exceed our total net worth. These factors and others can
turn an apparently beneficial acquisition into a financially disastrous
liability.
Drilling and Operating Risks - A large part of our business plan is to
drill exploratory wells. Exploratory wells are wells drilled into horizons with
little or no history of oil or gas production. Our business plan heightens many
of the
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considerable risks associated with drilling in general. Unexpected circumstances
may be encountered more often when we drill exploratory wells versus other types
of wells, because we are drilling at locations and into formations where no
wells have been drilled before. Moreover the probability that we will discover
and produce oil or gas from an exploratory well is lower than drilling a
development well because less is known about the area where the exploratory well
is drilled. Therefore, these risks may pose more of a danger to us than they
would to a company that focuses primarily on drilling development wells.
Development wells are wells drilled into known producing oil and gas fields and
horizons. We anticipate drilling or participating in the drilling of thirteen
(13) development wells and four (4) exploration wells during 2001. Depending on
the success of those wells, we may drill additional wells in 2001. However, even
if we drill and complete these wells as producing wells, they may not produce
sufficient net revenues to return a profit after drilling, operating and other
costs.
The cost of drilling, completing and operating wells is often uncertain. Our
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors. We insure risks typical to companies in our industry. Some
risks just come with the business; others may not be within the scope of
traditional insurance policies. In our case, the following are examples of the
operating hazards against which we cannot or do not insure:
o land title problems
o compliance with governmental requirements
o shortages or delays in the delivery of equipment and services
o unexpected pressure or irregularities in underground formations (other
than those causing a well to flow out of control above or below the
surface of the ground)
o mechanical problems encountered in drilling a well
o the collapse of the well bore, whether due to loss of underground
formation support or failure of the well bore casing
The occurrence of an event that is not covered by our insurance, or not fully
covered by insurance, could have a material adverse effect on our financial
condition and results of operations.
Uncertainty of Estimates of Reserves - The reserve data set forth in
this annual report are only estimates even when referred to as "proved."
Petroleum engineers consider many factors and make assumptions in estimating our
oil and gas reserves and future net cash flows. These estimates utilize
assumptions the Securities and Exchange Commission requires for all public
companies, including us. Estimates by definition are imprecise. Reservoir
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured exactly and of making assumptions based on
the process. Inherent uncertainties exist in the projection of future rates of
production and the timing of development expenditures. The timing of production
may be considerably different from the periods estimated. Assumptions are based
on factors such as historical production from the area as compared with
production from other areas, assumed effects of governmental regulation and
assumptions regarding future oil and gas prices, costs, taxes and capital
expenditures. Although we believe that our reserve estimates are reasonable, you
should expect that actual production, revenues and expenditures relating to our
reserves will vary from any estimates, and these variations may be material.
The estimates of future net revenues from the our proved reserves and the
present value of those revenues are based upon assumptions about future
production levels. These assumptions may be wrong. The SEC PV-10 values as
reported are based on a calculated present value of assumed future revenues.
Those calculations do not provide for changes in oil and gas prices or for
escalation of expenses and capital costs. "SEC PV-10" refers to present value
calculated using a 10% discount rate and other conditions required by the
Securities and Exchange Commission. The meaningfulness of such estimates is
highly dependent upon the accuracy of the assumptions and discount rate upon
which they are based. For example, the rules for determining SEC PV-10 require
us to use market prices as of December 31, 2000, to predict cash flow from our
properties. Because of the extremely high prices in effect at the end of
December 2000, we do not believe that extrapolation of those prices is justified
at this time, and our internal calculations of present value are less than the
SEC PV-10 value.
Markets - The availability of a ready market for any oil and gas that
we produce depends upon numerous factors that are beyond our control. These
factors include:
o federal and state regulatory developments and statutory enactments,
o the timing and extent of changes in commodity prices,
o exploratory and development drilling success,
o the amount of oil and gas available for sale,
o the availability of professional expertise and operating personnel,
o the availability of drilling equipment and drilling personnel,
o the availability of completing equipment and completing personnel,
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o crude oil imports,
o access to adequate capital,
o the availability of adequate pipeline and other transportation
facilities, and
o the marketing of competitive fuels and other matters affecting the
availability of a ready market, such as fluctuating supply and demand
Competition - The oil and gas industry is highly competitive in all of
its phases and in particular in the acquisition of unexplored acreage,
undeveloped acreage and existing production. There are a significant number of
operators engaged in oil and gas property acquisition and development, and our
competitive position depends on its geological, geophysical and engineering
expertise, on our financial resources, and on our ability to find, acquire and
prove new oil and gas reserves. We encounter strong competition in acquiring
economically desirable properties and in obtaining equipment and labor to
operate and to maintain our properties. That competition is from major and
independent oil and gas companies, many of which possess greater financial
resources and larger staffs than we have. Labor and equipment markets have shown
much volatility recently, and we cannot be certain that they will be available
at the prices we have budgeted.
Financial Reporting Impact of Successful Efforts Method of Accounting -
We use the "successful efforts" method of accounting for our investment in oil
and gas properties. This method of accounting can adversely affect our reported
earnings and thereby the market value of our stock because many drilling and
other costs may be required to be charged to expense earlier than might be the
case with "full cost" accounting, which is used by many oil and gas companies.
This charge to expense can result in reduced earnings or larger losses than
might be the case with the full cost accounting method.
Government Laws and Regulations - The oil and gas business is subject
to extensive federal rules and regulations. If we fail to comply with these
rules and regulations, we can incur substantial penalties. In general, the
regulatory burden on the oil and gas industry increases our cost of doing
business and decreases our profitability. Because these rules and regulations
are frequently amended or reinterpreted, the future cost or impact of complying
with these laws cannot be predicted with any certainty.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations. They also impose
other requirements relating to the exploration and production of oil and natural
gas. Many states have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging and abandonment of wells.
Our activities with regard to exploration, development and production of oil and
gas, including the operation of saltwater injection and disposal wells, are
subject to various federal, state and local environmental laws and regulations.
These laws and regulations can increase the costs of drilling and operating oil
and gas wells. Various governmental entities can impose civil and criminal fines
and penalties for noncompliance with these environmental laws and regulations.
Some environmental laws can impose joint and several retroactive liabilities,
without regard to fault or the legality of the original conduct. In addition, a
release of oil into water or other areas can result in us being held responsible
for the costs of cleaning up the release. That liability can be extensive,
depending on the nature of the release. Other environmental regulations impose
standards for the treatment, storage and disposal of both hazardous and
nonhazardous solid wastes. We, like others in the industry, generate hazardous
and nonhazardous solid waste in connection with our routine operations.
Additionally, these environmental laws and regulations require operators like
Venus to get permits or other governmental authorizations before undertaking
routine industry activities.
Because any violation of environmental statutes could affect a large area and
because our exploration projects are drilled into horizons where little is known
about the conditions we will encounter, we could incur substantial liability
under these environmental statutes. If a large environmental liability is
incurred, our costs would increase. Increased costs could reduce the
profitability and value of our properties. Given our dependence on debt
financing and the importance of our lender's valuation of our collateral, any
substantial decrease in the then-current estimates of total value could have
detrimental effects on our operations and business plan.
Potential Dilution - As of December 31, 2000, there were 2,131,416
shares of our common stock currently issuable upon exercise of outstanding
warrants or vested options. On January 23, 2001, warrants totaling 1,044,706
expired, leaving 1,086,710 shares issuable upon exercise of outstanding warrants
or vested options. The issuance of any of these shares could be considered
dilutive to then-existing stockholders and could depress our stock price. In
addition, the possibility that so many shares could be issued could further
depress the price of our common stock.
Control by Certain Stockholders - As of December 31, 2000, Range
Resources Corporation and our current officers and directors as a group
beneficially own more than forty three percent (43%) of the undiluted voting
power of the voting equity. One of our directors is the president of Range
Resources Corporation. Consequently, if our current officers and
9
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directors and Range Resources Corporation act together, those stockholders are
in a position to effectively control our affairs, including the election of all
of our directors and the approval or prevention of certain corporate
transactions that require majority stockholder approval.
Dependence on Key Personnel - We are dependent upon Eugene L. Ames,
Jr., Chairman of the Board and Chief Executive Officer, and John Y. Ames,
President and Chief Operating Officer. Mr. Eugene L. Ames, Jr. is our executive
with the most extensive contacts and relationships in the oil and gas industry.
John Y. Ames has extensive experience in land management and acquisition. We are
also dependent on Thomas E. Ewing and Bonnie Weise, both of whom are actively
involved in the technical application of the geoscience methods that are the
basis for our exploration activities. Dr. Ewing and Ms. Weise possess valuable
experience and knowledge with regard to oil and gas exploration, and their
technical expertise would be difficult to replace. We have employment agreements
with Mr. Ames, Jr., Dr. Ewing and Ms. Weise, all of which have non-competition
clauses. We do not carry key-man insurance on any of these individuals. Our
business and operations could be seriously harmed if Mr. Ames, Jr., Mr. J. Ames,
Dr. Ewing or Ms. Weise were to leave us.
Compliance with Nasdaq Listing Requirements - At December 31, 2000, we
had tangible net worth of $2.1 million which is $0.1 million above the minimum
required for a Nasdaq SmallCap Market(SM) listing. If in 2001 our net income is
not at least $500,000 or our tangible net worth decreases below $2 million, we
may be delisted from the Nasdaq SmallCap Market(SM). There is no assurance that
we will have either sufficient tangible net worth at December 31, 2001, or,
alternatively, sufficient net income for the year ending December 31, 2001 to
maintain our Nasdaq listing. From time to time over the past several months our
closing bid price has fallen below the Nasdaq minimum of $1 per share. There is
no assurance that the bid price will stay above the minimum required in
accordance with Nasdaq SmallCap Market(SM) listing requirements. If Nasdaq
delists us, our common stock will be traded on the OTC Bulletin Board or the
"pink sheets," or not traded at all. Many institutional and other investors
refuse to invest in stocks that are traded at levels below the Nasdaq SmallCap
Market(SM), and that could make our effort to raise capital more difficult. In
addition, the firms that currently make a market for our common stock could
discontinue that role. OTC Bulletin Board and "pink sheet" stocks are often
lightly traded or not traded at all on any given day. Any reduction in liquidity
or active interest on the part of investors in our common stock could hurt our
shareholders either because of reduced market prices or a lack of a regular,
active trading market for the our common stock.
Loan Covenant Defaults - During 1998 our financial situation
deteriorated in large part due to a downturn in oil and gas prices, a lack of
cash flow and an inability to raise capital to finance new drilling projects or
acquisitions of oil and gas properties. During the last half of 1998 and
throughout 1999 we received a series of waivers from our previous lender for
defaults of certain financial covenants in our revolving credit agreement,
including a waiver through March 31, 2000, for defaults existing as of December
31, 1999. We entered into our current credit facility in May of 2000. It has
similar financial covenants that we failed to satisfy as of December 31, 2000,
and we have requested and received from our current lender a waiver of such
defaults. Other than recording gains from sales of producing properties or other
assets, we do not expect to generate net earnings until more Development Wells
are drilled and successfully completed. Also, oil and natural gas prices are
volatile, and an unexpected drop in crude oil or natural gas prices could cause
us, at some point in the future, to be in default under the terms of the current
credit facility or its replacement. Accordingly, although our management intends
to maintain compliance with our current financial covenants, there is no
assurance that management can do so.
Substantial Capital Requirements - The cash flow generated by our
current operations is sufficient to fund our general and administrative
expenses, but we rely on bank and other financing to implement our business
plan. Our credit facility expires on May 8, 2001. Although we intend to
refinance the outstanding balance under our credit facility, to date, we have
not obtained a commitment from a lender for such a refinancing. Future
availability of credit will depend on the success of our development program and
our ability to stay in compliance with our credit facility debt covenants,
neither of which is assured.
Availability of Equipment and Personnel - Shortages or the high cost of
drilling rigs, equipment, supplies or personnel could delay or adversely affect
our development and exploration operations, which could have a material adverse
effect on our business, financial condition or results of operations. In the
event that drilling activity increases, we may experience increases in
associated costs, including those related to drilling rigs, equipment, supplies
and personnel, as well as the services and products of other vendors to the
industry. Increased drilling activity in the regions in which we operate will
likely decrease the availability of drilling rigs and related equipment and
personnel. We cannot assure you that costs will not increase further or that
necessary equipment and services will be available to us at economical prices.
Impact of Asset Impairments - Accounting rules require that we review
periodically the carrying value of our oil and natural gas properties for
possible impairment. Based on specific market factors and circumstances at the
time of prospective impairment reviews, and the continuing evaluation of
development plans, production data, economics and other factors, we may be
required to write down the carrying value of our oil and natural gas properties.
A write-down constitutes
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a non-cash charge to earnings, which reduces our equity. We may incur impairment
charges in the future, which could have a material adverse effect on our results
of operations in the period taken.
Hedging Activities - Our lender requires us to enter into contracts
that fix our revenue from the sales of our oil and gas production within an
agreed price range. We have done so with an affiliate of the our lender.
However, the lender is not obligated to observe a default by its affiliate, and
if the lender's affiliate defaults on its obligations under the hedging
agreements, that may affect our ability to service our debt obligations with our
lender. The possible effects include our default on our payment obligations and
our lender's foreclosure of its security interests in our oil and gas
properties.
REGULATIONS
General Federal and State Regulation - Our business is subject to
extensive federal rules and regulations. Failure to comply with such rules and
regulations can result in substantial penalties. The regulatory burden on the
oil and gas industry increases the cost of doing business and affects our
profitability. Because such rules and regulations are frequently amended or
reinterpreted, the future cost and impact of complying with such laws are
difficult to predict.
The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and natural gas.
Many states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from wells, and the regulation
of spacing, plugging and abandonment of such wells. Many states restrict
production to the market demand for oil and gas. Some states have enacted
statutes prescribing ceiling prices for gas sold within their boundaries.
Also, from time to time regulatory agencies impose price controls and
limitations on production by restricting the rate of flow of oil and gas wells
below natural production capacity in order to conserve supplies of oil and gas.
Environmental Regulation - The exploration, development and production
of oil and gas, including the operation of saltwater injection and disposal
wells, are subject to various federal, state and local environmental laws and
regulations. Such laws and regulations can increase the costs of planning,
designing, installing and operating oil and gas wells. Our domestic activities
are subject to a variety of environmental laws and regulations. A partial list
of those is:
o Oil Pollution Act of 1990,
o Clean Water Act,
o Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"),
o Resource Conservation and Recovery Act ("RCRA"), and
o Clean Air Act.
Civil and criminal fines and penalties may be imposed for non-compliance with
these environmental laws and regulations. Additionally, these laws and
regulations require the acquisition of permits or other governmental
authorizations before undertaking certain activities.
Under the Oil Pollution Act, if we release oil into water or other areas
designated by the statute, we can be held responsible for the costs of
remediating such a release, damages specified in the Act, and the damage to
natural resources. That liability can be extensive, depending on the nature of
the release.
CERCLA and comparable state statutes, also known as "Superfund" laws, can impose
joint and several retroactive liabilities, without regard to fault or the
legality of the original conduct. In practice, cleanup costs are usually
allocated among various responsible parties. Although CERCLA currently exempts
most petroleum products like crude oil, gas and natural gas liquids from the
definition of "hazardous substance," our operations may involve the use or
handling of other materials that may be classified as hazardous substances under
CERCLA. Additionally there is no assurance that the exemption will be preserved
in future amendments of the act.
RCRA and comparable state and local requirements impose standards for the
management, including treatment, storage and disposal, of both hazardous and
non-hazardous solid wastes. We generate hazardous and non-hazardous solid waste
in connection with routine operations. From time to time, proposals have been
made that would reclassify certain oil and gas wastes, including wastes
generated during drilling and production operations, as "hazardous wastes" under
RCRA. While state laws vary on this issue, state initiatives to further regulate
oil and gas wastes could have a similar impact.
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PRODUCT SALES AND MAJOR CUSTOMERS
Our production is generally sold at the wellhead to various oil and natural gas
purchasing companies, typically those that are in the areas where the oil or
natural gas is produced. Crude oil and condensate are typically sold at prices
that are based on posted field prices. All of our natural gas is sold on the
spot market. The term "spot market" refers to contracts with a term of six
months or less or contracts that call for a redetermination of sales prices
every six months or more often. We do not believe that the loss of one or more
of our current natural gas spot purchasers would have a material adverse effect
on our business because any individual spot purchaser could be readily replaced
by another spot purchaser who would pay a similar sales price. However, while we
believe that there will be a spot market available, that market is highly
sensitive to changes in current market prices, and a downward trend in spot
market prices can have a significant impact on our cash flow.
Three customers each accounted for approximately 10% or more of consolidated
revenues in 2000. Those are Flying J Oil & Gas, Inc. (26%), Duke Energy Field
Service, Inc. (13%) and Gulfmark Energy, Inc. (10%). In 1999, two customers each
accounted for approximately 10% or more of consolidated revenues. Those were
Stephens & Johnson Operating Company (13%) and Flying J Oil & Gas, Inc. (19%).
EMPLOYEES
As of March 15, 2001, the Company had 11 employees.
EXECUTIVE OFFICERS OF VENUS EXPLORATION, INC.
At March 15, 2001, our executive officers were Eugene L. Ames, Jr., John Y.
Ames, P. Mark Stark and Terry F. Hardeman.
Eugene L. Ames, Jr., age 67, became Chairman, Chief Executive Officer and a
director of our company in 1997. He has been in the oil and gas business since
1954 and has been associated with us and our predecessor entities since 1962 and
chief executive officer of those predecessor entities since 1991. Mr. Ames
received a B.S. degree in Geology from the University of Texas at Austin in
1955. He served as Chairman of the Independent Petroleum Association of America
from 1991 to 1993 and currently serves as a member of the policy committee of
the American Petroleum Institute, and chairman of the Texas Oil and Gas
Association. He is also the Vice Chairman of the Board of Directors of the
Southwest Research Institute.
John Y. Ames, age 45, became President, Chief Operating Officer and a director
of our company in 1997. He is a graduate of the University of Texas at Austin
with a BBA degree in Petroleum Land Management. He had eight years of experience
in the energy business before becoming associated with us and our predecessor
entities as a Vice President in 1984. He became Executive Vice President of our
predecessor entities in 1995 and President and Chief Operating Officer in 1996.
He is the son of Eugene L. Ames, Jr.
P. Mark Stark, age 46, joined our company in October 2000 and was named Chief
Financial Officer in December 2000. He comes to us with 17 years of experience
at the CFO level, much of it in the energy arena. From December 1998 through
October 2000, Mr. Stark was the Executive Vice President for Alamo Water
Refiners, Inc. From December 1995 through December 1998, he was the Chief
Financial Officer for Dawson Production Services, Inc. ("DPS" - NYSE), a
publicly held oil field service company. Mr. Stark received his Bachelor of
Business Administration degree in Finance from the University of Texas in 1977,
and his Masters of Business Administration degree in 1978 from Southern
Methodist University.
Terry Hardeman, age 60, joined our company's predecessor in 1990. He was named
Chief Accounting Officer in December 2000 and is responsible for accounting,
taxation and day-to-day management of Venus' accounting activities. Mr.
Hardeman, a Certified Public Accountant in the State of Texas, has held senior
financial positions with other San Antonio area companies and comes to industry
after having been in public accounting for five years with KPMG LLP (formerly
KPMG Peat Marwick). Mr. Hardeman received a Bachelor of Science degree in
Accounting from Stephen F. Austin State University and his Masters of Business
Administration from the University of Houston.
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DEFINITIONS OF CERTAIN OIL AND GAS TERMS
The terms defined in this section are used throughout this Annual Report on Form
10-K.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas and related compounds at standard
conditions.
Bcfe. Equivalent of one billion cubic feet of natural gas. In reference to
natural gas, natural gas equivalents are determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Btu. One British thermal unit. The quantity of heat required to raise the
temperature of one pound of water one degree Fahrenheit at standard conditions.
Completion. The installation of permanent equipment for the production of oil or
gas, or, in the case of a dry hole, the reporting of abandonment to the
appropriate authority.
Developed Acreage. The number of acres that are allocated or assignable to
producing wells or wells capable of production.
Development Well. A well drilled or to be drilled within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon believed to be
productive.
Dry Hole or Dry Well. A well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as a producing oil or gas
well.
Exploitation. The process whereby the value of a property is increased by
working over existing wells, by making new completions in existing wells and by
conducting other similar operations intended to increase production from
existing wells in a developed area.
Exploratory Well. A well drilled to find and to produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir
beyond the currently expected limits of the known reservoir. These wells involve
a high degree of risk, given the unknown nature of the horizons being tested.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Mbbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mmbtu. One million Btu's.
Mcf. One thousand cubic feet of natural gas and related compounds at standard
conditions.
Mcfe. The equivalent of one thousand cubic feet of natural gas. In reference to
natural gas, natural gas equivalents are determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mmcfe. The equivalent of one million cubic feet of natural gas. In reference to
natural gas, natural gas equivalents are determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net Acres or Net Wells. The sum of the fractional Working Interests owned in
Gross Acres or Gross Wells.
Production Cost. Also referred to as lifting cost, it is the cost of operation
and maintenance of wells, related equipment and facilities that are expensed as
incurred as a part of the cost of oil and gas produced; e.g., labor to operate
the wells and facilities, repair and maintenance expenses, materials and
supplies consumed, taxes and insurance on property, and severance taxes.
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PV-10 Value, or Present Value of Estimated Future Net Revenues. The present
value of estimated future net revenues as of a specified date, after deducting
estimated production and ad valorem taxes, future capital costs and operating
expenses, but before deducting federal income taxes. The estimated future net
revenues are 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.
Productive Well. A well that is producing oil or gas or that is capable of
production.
Prospect. An area that has been interpreted to be prospective for commercial
hydrocarbon accumulation based on seismic evaluations; leases may or may not
have been acquired in the area of the Prospect.
Prospect Lead. An area that preliminary evaluations suggest may be prospective
for commercial hydrocarbon accumulation; usually no seismic studies will have
been conducted on such an area, nor will have any leases been acquired in it.
Proved Developed Reserves. Reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas and natural
gas liquids that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions.
Proved Undeveloped Reserves, or PUD. Proved Reserves that are under undeveloped
spacing units that are so close and so related to developed spacing units that
they may be assumed with confidence to become commercially productive when
drilled.
Royalty Interest. An interest in an oil and gas property entitling the owner to
a share of the oil and gas produced, free of costs of production.
Seismic Data. Geophysical information collected by transmitting sound waves into
the earth from a transmitter, or source, and measuring, with appropriate
receivers, the time of the sound waves' arrival and their intensity when they
are reflected or refracted back to the surface.
2-D seismic data is collected along a surface line of sources and receivers,
giving a section representing a slice through the earth.
3-D seismic data is collected by distributing sources and receivers over an
area, yielding a volume of information representing the 3-dimensional section of
earth beneath the area being studied. The improved imaging of 3-D data makes it
the preferred advanced technological method of attempting to determine the
location, extent and properties of hydrocarbon accumulations.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains Proved Reserves.
Working Interest, or WI. The cost-bearing operating interest that gives the
owner the right to drill, to produce and to conduct operating activities on the
property and to share a proportionate part of production.
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ITEM 2. PROPERTIES
OIL AND NATURAL GAS RESERVES
As of December 31, 2000, Ryder Scott Company, independent petroleum engineers,
evaluated all of our properties in order to generate our PV-10 Value. The PV-10
Values shown in this Annual Report on Form 10-K are not intended to represent
the current market value of the estimated net Proved Reserves of oil and natural
gas properties we own. Prices and costs have been held constant based on
December 31, 2000, prices and costs.
We have not filed any estimate of oil or gas reserve information with any
federal authority or agency other than the U.S. Securities and Exchange
Commission (SEC). The following table summarizes our estimates of our net Proved
Reserves and their PV-10 Value as of December 31, 2000.
PROVED RESERVES
(AS OF DECEMBER 31, 2000)
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
----------- ----------- ----------
Oil and Condensate (Mbbls) 554.25 398.11 952.36
Natural Gas (Bcf) 2.49 2.63 5.12
Combined Equivalent BCF (Bcfe) 5.81 5.02 10.83
PV-10 Value (in thousands)(1) 14,212.37 16,612.36 30,824.73
=========== =========== ==========
PROVED RESERVES BY STATE
(AS OF DECEMBER 31, 2000)
TOTAL GAS PERCENT OF PV-10 PERCENT
GROSS OIL GAS EQUIV. TOTAL VALUE OF PV-10
STATE WELLS (MBBL) (BCF) (BCFE)(3) (BCFE) ($1,000)(1) VALUE
- ---------------- --------- ------------ ------------ ---------------- ---------------- ------------ ------------
Texas 79 387 4.47 6.80 62.8% 26,212 85.0%
Utah 7 362 .26 2.43 22.4% 2,576 8.4%
Oklahoma 211 187 .36 1.48 13.7% 1,933 6.3
Other (2) 10 16 .02 .12 1.1% 104 .3
--------- ------------ ------------ ---------------- ---------------- ------------ ------------
TOTAL 307 952 5.11 10.83 100.0% 30,825 100.0%
========= ============ ============ ================ ================ ============ ============
(1) Pre-tax
(2) Other states are Alabama, Louisiana and California. All of our Proved
Reserves are in the United States.
(3) We used a 6:1 ratio (mcf of gas/-bbl of oil) for the conversion.
The foregoing table represents an increase in value but a decrease in volume of
Proved Reserves as compared with December 31, 1999. The increase in reserve
value is primarily due to the increase in oil and natural gas prices at year-end
2000 as compared to year-end 1999. The decrease in amount of reserves is
primarily due the downward revision of reserves of some existing properties and
normal production. See Note 13 of Notes to Consolidated Financial Statements
(Supplementary Oil and Gas Disclosures) for further information.
The reserve data presented in this Annual Report on Form 10-K are estimates
only. In general, estimates of economically recoverable oil and gas reserves and
of the future net revenues therefrom are based upon a number of variable factors
and assumptions, such as historical production from the subject properties, the
assumed effects of regulation by governmental agencies and assumptions
concerning future oil and gas prices and future operating costs, all of which
may vary considerably from actual results. All reserves are evaluated based on
the assumption that all reported data are stated at standard temperature and
pressure. If that assumption proves to be incorrect, it may have a substantial
effect on estimated gas reserves. All such estimates are to some degree
speculative, and classifications of reserves are only attempts to define the
degree of speculation involved. For these reasons, estimates of the economically
recoverable oil and gas reserves attributable to any particular group of
properties, classifications of such reserves based on risk of recovery, and
estimates of the future net revenues expected therefrom prepared by different
engineers or by the same engineers at different times may vary substantially.
Therefore, we emphasize that the actual production, revenues, severance and
excise taxes, development and operating expenditures with respect to our
reserves will likely vary from such estimates, and such variances could be
material.
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Estimates with respect to Proved Reserves that may be developed and produced in
the future are often based upon volumetric calculations and upon analogy to
similar types of reserves rather than actual production history. Estimates based
on these methods are generally less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon
production history will most likely result in variations in the initially
estimated reserves and those variations may be substantial.
In accordance with applicable requirements of the Securities and Exchange
Commission, the estimated discounted future net revenues from estimated Proved
Reserves are based on prices and costs as of the date of the estimate unless
such prices or costs are contractually determined at such date. Actual future
prices and costs may be materially higher or lower. Actual future net revenues
also will be affected by factors such as actual production, supply and demand
for oil and natural gas, curtailments or increases in consumption by natural gas
purchasers, changes in governmental regulations or taxation and the impact of
inflation on costs.
DRILLING ACTIVITY
We drilled, or participated in the drilling of, the following number of wells
during the periods indicated:
DEVELOPMENT WELLS
-------------------------------------------------------------------------
GROSS WELLS NET WELLS
-------------------------------------- ----------------------------------
YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
- ---- ----------- ----------- -------------- ----------- ----------- ----------
1998 4.00 1.00 5.00 1.44 1.00 2.44
1999 3.00 1.00 4.00 .11 .07 0.18
2000 2.00 -- 2.00 .17 -- .17
----------- ----------- -------------- ----------- ----------- ----------
Totals 9.00 2.00 11.00 1.72 1.07 2.79
=========== =========== ============== =========== =========== ==========
EXPLORATORY WELLS
-------------------------------------------------------------------------
GROSS WELLS NET WELLS
-------------------------------------- ----------------------------------
YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
- ---- ----------- ----------- -------------- ----------- ----------- ----------
1998 1.00 2.00 3.00 .26 .87 1.13
1999 1.00 -- 1.00 .07 -- 0.07
2000 0.00 1.00 1.00 .00 .10 .10
----------- ----------- -------------- ----------- ----------- ----------
Totals 2.00 3.00 5.00 .33 .97 1.30
=========== =========== ============== =========== =========== ==========
PRODUCTIVE WELLS
AS OF DECEMBER 31, 2000
-------------------------------------------------------------------------
GROSS WELLS NET WELLS
-------------------------------------- ----------------------------------
STATE OIL GAS TOTAL OIL GAS TOTAL
- ----- ----------- ----------- -------------- ----------- ----------- ----------
Texas 46 33 79 2.524 5.042 7.566
Oklahoma 194 17 211 15.189 1.273 16.462
Utah 4 3 7 1.002 1.400 2.402
Other (1) 9 1 10 2.204 .040 2.244
----------- ----------- -------------- ----------- ----------- ----------
Totals 253 54 307 20.919 7.755 28.674
=========== =========== ============== =========== =========== ==========
(1) Other states are Michigan, Alabama, Louisiana and California.
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ACREAGE
The following table sets forth our Developed and Undeveloped Acreage as of
December 31, 2000:
DEVELOPED AND UNDEVELOPED ACREAGE
- -------------------------------------------------------------------------------------------
GROSS ACRES NET ACRES
---------------------------------- ----------------------------------
STATE DEVELOPED UNDEVELOPED DEVELOPED UNDEVELOPED
- ----- ----------------- ---------------- ----------------- ----------------
Oklahoma 13,695 179 573 163
Texas 7,163 14,460 2,381 3,205
Utah 4,943 -- 1,536 --
Louisiana -- 780 -- 780
Alabama 400 -- 136 --
California 400 -- 26 --
Michigan 80 880 40 400
Kansas -- 480 -- 480
----------------- ---------------- ----------------- ----------------
Totals 26,681 16,779 4,692 5,028
================= ================ ================= ================
PRODUCTION
The following table summarizes our net oil and gas production, weighted average
sales prices and average production (lifting) costs per unit of production for
the periods indicated:
UNITS OF PRODUCTION AVERAGE SALES PRICE AVERAGE
----------------------------- -----------------------------
OIL GAS OIL GAS LIFTING COST*
-------------- -------------- -------------- -------------- --------------
YEAR (MBBLS) (BCF) $/BBL $/MCF $/MCFE
- ----
1998 119 .572 12.84 2.15 1.25
1999 84 .316 17.54 2.23 1.25
2000 94 .310 28.17 4.12 1.66
-------------- -------------- -------------- -------------- --------------
*Includes severance taxes and ad valorem taxes.
NOTE: ALL OF OUR PRODUCTION IS IN THE UNITED STATES.
During 2000, we sold two properties in Wharton County, Texas, and one property
in Seward County, Kansas. Production for 1999 attributable to the properties
sold totaled 1,505 barrels of oil and 18,779 Mcf of gas. Not reflected in the
table above is our share of production attributable to our equity interest in
EXUS Energy, which for 1999 totaled 544,200 Mcf at an average price of $2.86 per
Mcf and average lifting cost of $0.39 per Mcf. We acquired our interest in EXUS
Energy on June 30, 1999, and sold it on December 31, 1999.
TITLE TO PROPERTIES
Over 99% of our properties are Working Interests derived from oil and gas leases
on property owned by third parties. None of our properties are mineral or fee
interests. We usually perform title research before acquiring leases or
interests in leases, and we believe that we have satisfactory title to our
producing properties. The degree of research we conduct varies depending on the
value initially assessed to the property, whether the property is producing at
the time of acquisition, and other factors. The properties are usually subject
to the rights of lessors who are paid a Royalty Interest out of production. They
are also often subject to overriding royalties and other burdens, none of which
we believe to be a material burden on the value of our interest. Substantially
all of our properties are and will continue to be subject to liens and mortgages
to secure borrowings under our credit facility.
Substantially all of the properties that we own are subject to exploration or
development agreements with third parties. The exploration and development
agreements are subject to "Area of Mutual Interest," or "AMI," provisions that
give the third party participants certain limited rights of first refusal on
interests acquired within the AMI. If the third party elects not to
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acquire such interest, in a majority of cases we have the right to acquire the
third party's proportionate part of the interest. Once interests are acquired,
the parties to the agreements usually also have an election before a well is
drilled. If a party elects not to drill, we usually have the right to acquire
certain interests from the non-drilling party, but depending upon the size of
the interest and the cost of the proposed well, we may or may not elect to
acquire that interest. In the exploration and development projects in which we
place the most value, a third party election not to drill could leave little
value to our interest unless we could find another third party to assume the
non-drilling party's interest.
OIL AND GAS PROPERTIES
Constitution Field - We hold approximately 4,946 gross (4,538 net) acres in this
field and own a 15% working interest in the acreage block and we are the
operator. We shot a 3D seismic survey of the Constitution field in 1999. Our
technical staff processed and interpreted this data and integrated the
information obtained from this seismic survey with other subsurface geological
information. The results of our technical analysis have caused our staff to
estimate that 6 proved, undeveloped drill sites with a total of 11 zones exist
in the Constitution field. The independent engineering consulting firm of Ryder
Scott Company concurred with this estimate. During November 1999, we completed a
successful fracture stimulation of the No. 1 Westbury Farms, which was
originally completed in March 1998 as a gas condensate well through perforations
in the middle Yegua Formation. During 2000 the well produced an estimated daily
average production of 3.0 million cubic feet of gas and 388 barrels of
condensate through 13/64" choke with 4,000 pounds per square inch tubing
pressure. In 2000, we successfully completed a development well, the #1 Apache
Gas Unit in the Westbury Middle Yegua Sand. This well began generating sales on
October 2, 2000. The initial production rate was 3.682 million cubic feet of gas
per day (MMCF) and 312 barrels of condensate per day flowing through 15/64 inch
choke with 3,870 #psi flowing tubing pressure. On December 20, 2000, we spudded
the Paggi #1, which was completed in February 2001. The initial production rate
was 3.700 million cubic feet of gas per day (MMCF) and 475 barrels of condensate
per day flowing through 22/64 inch choke with 1,986 #psi flowing tubing
pressure. On February 26, 2001, we commenced drilling the fourth well in this
field, and it is targeted for completion in multiple productive reservoirs.
During 2001, we plan on drilling three more wells in this field, with four wells
targeted to be drilled in 2002.
Jackson Parish, La. - On June 30, 1999, we acquired an interest in oil and gas
producing properties in Jackson Parish, Louisiana. The total purchase price was
$27.6 million; however in order to finance the acquisition at no net cash outlay
to us, we sold 50% of the acquisition to another company that agreed to arrange
100% of the capital required to close the acquisition. To facilitate the
financing of the acquisition with our 50% co-venturer, the properties were
acquired by a limited liability company in which we owned 50%. On December 31,
1999, we sold our interest in the properties, and we realized a pre-tax gain on
the sale of $4.7 million, of which $4.3 million was recorded in 1999, and the
balance was recorded in 2000 when contingencies related to part of the
properties sold were cleared. This acquisition was a product of our strategy
under which our explorationists, after conducting regional trend studies in
areas they deemed to be prospective, identify producing oil and gas fields with
exploitation potential as acquisition targets. Then, our management utilized its
contacts with larger companies, and we were successful in our effort to acquire
those properties.
Sale of Properties in 2000 - In 2000, we sold two properties in Wharton County,
Texas, and one in Seward County, Kansas, for an aggregate gross price of
approximately $17,000.
OFFICE LEASE
In May 1997, we relocated our executive and operating offices to San Antonio,
Texas, where we occupy premises of approximately 12,570 useable square feet
pursuant to a lease that expires on December 31, 2002. We recently sub-leased
that space and will be moving into a smaller area in the same building. The
lease of the new space expires on May 31, 2006. The lease of the San Antonio
office space provides for increased rents at stated amounts and intervals and an
adjustment for variations in utility costs.
We also lease an office in Houston, Texas. The Houston office address is 363 W.
Sam Houston Parkway, Suite 490, Houston, Texas 77060. That lease terminates on
August 26, 2001. We no longer have employees in Houston, and we have subleased
this office space. Our annual rental expense is approximately $237,000.
See "Item 1 - BUSINESS" for additional information concerning our oil and gas
properties.
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ITEM 3. LEGAL PROCEEDINGS
From time to time, we are involved in litigation relating to claims arising out
of our operations in the normal course of business. As of December 31, 2000, we
were not engaged in any legal proceedings that are expected, individually or in
the aggregate, to have a material adverse effect on the our financial condition
or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
An Annual Meeting of our Stockholders was held on December 12, 2000, for the
following purposes:
o To elect eight (8) directors to serve until the next Annual Meeting of
Stockholders
o To ratify amendments to our 1997 Incentive Plan of the Company to remove
some of the limitations on the number and type of awards that may be
granted under the Plan and to increase the number of shares of common
stock that may be awarded under the Plan
o To ratify the amendment to our Certificate of Incorporation to increase
the number of authorized shares of common stock to 50,000,000 shares
o To ratify the amendment to our Certificate of Incorporation to grant our
Board of Directors the power to determine the voting rights of each share
of preferred stock that may be issued
o To ratify the appointment of KPMG LLP as our independent certified public
accountants for the fiscal year ended December 31, 2000
All the matters were approved by the vote of our stockholders, and the results
are tabulated below:
FOR AGAINST ABSTAIN OR WITHHELD
---------------------- ---------------------- ---------------------
(1) Election of Directors
E.L. Ames, Jr. 9,213,271 2,812 None
John Y. Ames 9,213,271 2,812 None
J.C. Anderson 9,213,281 2,802 None
Martin A. Bell 9,213,271 2,812 None
James W. Gorman 9,213,271 2,812 None
Michael E. Little 9,213,281 2,802 None
Jere W. McKenny 9,213,271 2,812 None
John H. Pinkerton 9,213,281 2,802 None
(2) Amendments to 1997 Incentive Plan 8,778,664 434,639 2,777
(3) Increase number of Authorized Shares
to 50,000,000 9,190,795 24,127 1,159
(4) Amendment to Certificate of
Incorporation regarding
voting rights of Preferred
Stock 8,597,975 21,384 3,892
(5) Ratification of KPMG LLP as auditors 9,211,329 4,088 666
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Our Common Stock is traded on the NASDAQ SmallCap Market(SM) under the symbol
"VENX." The following table sets forth the range of high and low closing bid
prices for each quarterly period during the two most recent fiscal years as
reported by the NASDAQ SmallCap Market(SM). All SmallCap quotations represent
inter-dealer quotations, without retail mark-up, mark-down or commission, and
may not represent actual transactions.
HIGH LOW
-------- ---------
2000
First Quarter $ 2.0000 $ .4375
Second Quarter 1.0625 .6562
Third Quarter 1.1875 .6250
Fourth Quarter 1.8750 .7500
1999
First Quarter $ 1.7500 $ .8125
Second Quarter 1.8750 .7500
Third Quarter 1.8750 1.1875
Fourth Quarter 1.4375 .9375
On March 19, 2001, the closing bid price for our Common Stock was $.875 per
share.
We had 977 stockholders of record as of March 19, 2001, (includes nominee
holders such as banks and brokerage firms that hold shares for beneficial
owners). We have not paid dividends in recent periods and have no present
intention to resume payment of dividends. We presently intend to reinvest our
net revenues in our ongoing business.
Potential Dilution - As of December 31, 2000, there were 2,131,416 shares of our
common stock currently issuable upon exercise of outstanding warrants or vested
options. On January 23, 2001, warrants totaling 1,044,706 expired, leaving
1,086,710 shares issuable upon exercise of outstanding warrants or vested
options. The exercise prices and expiration dates for all outstanding warrants
and options are as follows:
NUMBER OF OPTIONS OR WARRANTS EXERCISE PRICE EXPIRATION DATE
- ------------------------------ ---------------------------- --------------------------------------
179,016 $0.6562 - $1.0470 Various times in 2001 through 2009
136,801 $1.1191 March 2009
133,554 $1.1520 December 2005
108,311 $1.2310 March 2004
20,000 $1.2500 August 2003
100,000 $1.3125 July 2004
24,526 $1.4900 March 2009
160,000 $1.5000 June 2005
20,000 $1.8750 January 2006
29,000 $2.00 - 2.1250 various times in 2007 and 2008
154,002 $3.29 - 3.7125 various times in 2004 and 2008
----------
TOTAL - 1,086,710
The issuance of any of these shares could be considered dilutive to
then-existing stockholders and could depress our stock price. In addition, the
possibility that so many shares could be issued could further depress the price
of our common stock.
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We entered into our current credit facility with a bank effective May 5, 2000.
Under terms of the credit facility, we are not permitted to declare or to pay
any dividend on any of our shares or to make any distribution to our
stockholders.
Effective September 18, 2000, the Executive Committee of the Board of Directors
approved a plan for the repurchase of up to 300,000 shares of our common stock.
With the consent and approval of our lender under our credit facility, we have
the authority to purchase $100,000 worth our common stock in open market
transactions at prices related to the independent market for common stock, all
in accordance with the terms and provisions of Rule 10b-18 ("Rule 10b-18") under
the Securities and Exchange Act of 1934, as amended. Unless renewed by action of
the Board of Directors, the repurchase plan, as amended, shall terminate on the
earlier of the purchase of the 300,000 shares or June 15, 2001.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth for the periods indicated our selected historical
financial data. The selected historical financial data as of and for each of the
years in the five-year period ended December 31, 2000, have been derived from
our audited historical financial statements. We acquired or divested significant
producing oil and gas properties in all the periods presented, with most of the
activity concentrated in 1999. Those acquisitions affect the comparability of
the historical financial and operating data for the periods presented. The
information below should be read in conjunction with Item 7 - "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and
our Historical Financial Statements and the notes thereto included elsewhere in
this Annual Report on Form 10-K.
SELECTED FINANCIAL DATA
AS OF AND FOR THE FIVE-YEAR PERIOD ENDED DECEMBER 31, 2000
(IN THOUSANDS, EXCEPT PER SHARE INFORMATION)
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
Total revenues $ 3,718 $ 2,184 $ 2,805 $ 2,476 $ 543
Dividends paid(1) -- -- -- -- 35
Income (loss) before extraordinary items (1,266) 1,010 (8,324) (4,168) (2,007)
Net income (loss) (1,516) 1,010 (8,670) (4,168) (2,007)
Per common share:
Net income (loss) -- Basic (.13) 0.09 (0.87) (0.57) (0.60)
Net income (loss) -- Diluted (.13) 0.09 (0.87) (0.57) (0.60)
Long term debt -- 1,750 -- 2,005 --
Other long-term liabilities 13 18 23 27 --
Convertible redeemable preference shares -- -- -- -- 4,955
Total assets 7,117 24,465 8,136 12,931 4,343
(1) Our predecessor was a privately held S Corporation. Dividends paid in 1996
were paid by the S Corporation.
Fiscal 1999 includes pre-tax gain of $4.8 million from the sale of properties.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
We were incorporated in the State of Delaware in September 1985 as Xplor
Corporation. In 1997, through a reverse merger, the majority of the present
management team was put into place, implementing our current exploration and
development focus. After that merger and change of management, we changed our
name to Venus Exploration, Inc. We are publicly traded on the Nasdaq SmallCap
Market(SM) under the symbol VENX. Our management team has been responsible for
the discovery, development and exploitation of relatively significant reserves
of oil and gas for our privately-held predecessor companies over the last 30
years.
In our current form, we are an independent oil and gas exploration and
development company. We acquire producing oil and gas properties onshore in the
United States and apply advanced geoscience technology to the exploration for
and exploitation of undiscovered reserves. We presently have oil and gas
properties, acreage and production in seven states, including Texas, Louisiana,
Oklahoma and Utah. Our current focuses are:
o the Expanded Yegua Trend of the Upper Texas and Louisiana Gulf Coast,
and
o the Cotton Valley Trend of East Texas and Western Louisiana
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In 2000 we participated in drilling four wells. One of the four wells was
exploratory, and the other three were development wells. Two of the development
wells were completed as gas wells, one in the Constitution Field, Jefferson
County, Texas, and the other in the Welburton Field, Latimer County, Oklahoma.
One will be tested on pump as an oil well in the Midway-Holst Field, San
Patricio County, Texas, and one was drilling at year end and completed in
February 2001 as a gas well. In 2001, among others, we anticipate participating
in two wells in the Texas Panhandle; one reentry and one sidetrack to develop
reserves in the Yegua Formation in Wharton County, Texas; three or more wells in
the Constitution Field, Jefferson County, Texas; and two wells in another Yegua
Formation gas field in Jefferson County, Texas. One of the development wells,
the #1 Kolander, is currently drilling in the Constitution Field and should be
completed in April of this year. Because of the increased gas price, increased
demand for natural gas and increased cash flows within the industry, we expect
to increase generation of exploratory prospects in 2001.
This prospect generation activity will primarily be accomplished by utilizing
geological and geophysical data supporting prospects and leads in our database
and prospect inventory. We already have oil and gas leases on some of the
properties in our prospect inventory. As to the other properties in our prospect
inventory, we will attempt to obtain oil and gas leases where the prospects
appear promising. From time to time, we may acquire new prospects from
independent geologists or other exploration and production companies. In
expanding our exploration activity, we expect to continue our historical
practice of selling participation to industry venturers in order to reduce our
financial risk and capital requirements.
Our Proved Reserves as of December 31, 2000, totaled 10.8 Bcfe, a decrease of .3
Bcfe from the 11.1 Bcfe we reported at year-end 1999, a 2.7% decrease.
Production for 2000 totaled .9 Bcfe. Production was partially offset by .6 Bcfe
of net new reserves added through discoveries, extensions and revisions of
reserves on our existing properties. In 2000, average daily net production
increased to 2,400 Mcfe/day from 2,250 Mcfe/day in 1999, a 6.7% increase. The
increase was due to increased production from existing wells and the completion
of a new well.
During 1999, due to the significant decline in oil and natural gas prices during
1998 and our shortage of capital, we emphasized acquiring and expanding reserves
in existing oil and gas fields rather than exploring for new reserves in
unestablished areas. At the end of 1999 and during 2000, we began working on
exploration projects again. In November 1999 we successfully restimulated our #1
Westbury Farms well in the Constitution Field, Jefferson County, Texas. In 2000,
we participated in two wells in the Constitution Field in order to help define
the limits of this exploratory project. During 2000, we also expanded our
exploration activity in the Bossier/Cotton Valley trend in East Texas. We
acquired a license to obtain 3-D seismic data covering a 100-mile area as a
component of a joint venture entered into with a major oil company. We are the
manager of the joint venture, and the major oil company as co-venturer retains
the right to a 50% participating interest in lease acquisition and in drilling
exploratory wells within this area of mutual interest ("AMI"). We currently own
rights to 100% of the joint venture acreage, subject to the right of the major
oil company to take 50%. Of the area to be explored, leases covering
approximately 4,500 acres have been acquired. We are also acquiring leases on
other prospects in the Bossier/Cotton Valley trend in East Texas.
The 2001 budget provides for capital expenditures of approximately $6.2 million
for projects that include the drilling and completion of 13 development wells,
drilling 4 exploratory wells, 2-D and 3-D seismic acquisition for exploration
projects, and acreage acquisition, all of which is subject to obtaining
financing. Our share of the 4 exploration wells and the seismic acquisition is
budgeted at $100,000. We anticipate that our interest in the exploration
projects will be "sold down" or reduced by selling participating interests to
industry co-venturers. This is done to reduce financial risk and to spread our
available exploration capital over more prospects. The actual timing of the
drilling of the wells is dependent upon many unpredictable factors such as the
availability of capital and of drilling rigs. Any of these factors could
postpone or enlarge the needed expenditures. The only contractual commitment for
any of the budgeted costs is in our contract with Greywolf Drilling Company in
the Constitution Field where we are in a continuous development program.
However, the commitment is only for the next well after the #1 Kolander, which
is currently drilling. In addition, depending on the level of success of the
development wells and exploitation wells, we may drill additional wells during
2001; however, we are not able to budget such additional wells at this time.
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RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2000, COMPARED WITH YEAR ENDED DECEMBER 31, 1999
We reported a net loss of $1.5 million for 2000 versus a net income of $1.0
million for 1999. In 1999, we reported $4.8 million pre-tax gains on the sale of
oil and gas properties. Our oil and gas production was 878 Mmcfe in 2000,
compared to 821 Mmcfe in 1999, an increase of 7%. Average oil prices increased
from $17.54 per barrel in 1999 to $28.17 in 2000, a 61% increase. Average
natural gas prices increased from $2.23 per Mcf to $4.12, an 85% increase. As a
result of the increase in production and prices, oil and gas revenue increased
by $1.5 million to $3.7 million in 2000 from $2.2 million in 1999.
Oil and gas production costs in 2000 were $1,456,335 ($1.66 per Mcfe) compared
with $1,025,947 in 1999 ($1.25 per Mcfe). The increase in total production
expense of $.41 per Mcfe is due to an increase in production taxes of $.22 per
Mcfe (54% of the increase), which is a result of higher prices in 2000. Well
workover expense increased $.08 Mcfe (19%), and lease operating expense
increased $.11 per Mcfe (27%).
2000 production or lifting cost as a percentage of oil and gas sales decreased
to 39%, compared with 47% in 1999. This decrease is almost entirely due to
higher oil and gas prices since lifting cost per Mcfe increased between the two
periods as mentioned in the immediately preceding paragraph.
During the first quarter of 1999, we sold our West Virginia properties and two
producing Texas wells. Production for 1999 attributable to the properties sold
totaled 18.313 Mmcfe of gas. Revenues less operating expenses of the properties
sold totaled $37,047 in 1999.
During 2000, we recorded no impairment expense as compared to $.5 million
recorded in 1999. We review for impairment whenever circumstances indicate that
the carrying value of an asset may not be recoverable. Such reviews were done
for both 2000 and 1999. We follow SFAS No. 121 and recognize an impairment when
the net future cash flow that is expected to be generated by a long-lived asset
is less than the net carrying value of the asset. This comparison is performed
on a field by field basis. If the net carrying value is greater, an impairment
write down is recorded in the amount of the difference between the net carrying
value and fair value. Fair value is based on estimated future discounted cash
flows to be generated. Future cash flows for both the impairment test and for
determining the amount of the write down are estimated using only proved
reserves and our estimate of future product prices. Our current future price
assumption is based on New York Mercantile Exchange ("Nymex") futures pricing of
crude oil and natural gas contracts for the periods that we consider to have
meaningful trading volumes. By conducting the comparison on a field by field
basis we may record an impairment even though the total estimated value of all
our properties is greater than their total net carrying value.
Exploration expense, including geological, geophysical and seismic data
acquisition and analysis and dry hole expenses of $1,159,132 in 2000 increased
by $494,551 from $664,581 in 1999. The increase is due to an increase in
exploration activity, (primarily with respect to our activity in the
Bossier/Cotton Valley trend in East Texas), the abandonment of an exploratory
prospect in Goliad County, Texas, and an increase in salaries as a result of the
reinstatement of salaries that were reduced as part of our restructuring plan
initiated in 1998.
Depreciation, depletion, and amortization (DDA) expense of $694,743 ($0.79 per
Mmcfe) in 2000 increased by $31,507 from $663,236 ($.81 per Mcfe) in 1999.
Approximately $45,772 of the increase is due to the increase in sales volume,
and that amount is partially offset by a decrease of $14,328, attributable to
lower DDA rates. The lower DDA rates for 2000 are due to higher estimated proved
reserves as a result of using higher prices in estimating proved reserves and
lower net carrying value of our oil and gas properties as a result of prior year
impairments.
During 2000, general and administrative expense of $1,894,204 decreased $396,813
from $2,291,017 in 1999. This decrease was primarily due to various cost
reduction measures implemented in late 1998 and throughout 1999. These cost
reduction measures were primarily related to reductions in the number of
employees. The amounts include costs of severance packages for former employees.
Interest expense was $169,217 in 2000, compared to $895,602 in 1999. The
$726,385 decrease is primarily due the retirement of the debt in 1999 and early
2000. During 1999 we recorded interest expense of $429,333 related to the EXCO
note and $359,111 related to bank debt. Both debts were repaid in late 1999 and
early 2000. Interest expense includes amortization of deferred financing cost of
$72,367 in 2000 and $29,202 in 1999. The average daily balances of
interest-bearing debt was $1.5 million in 2000, compared to $8.3 million in
1999.
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YEAR ENDED DECEMBER 31, 1999, COMPARED WITH YEAR ENDED DECEMBER 31, 1998
We reported after tax net income of $1.0 million for 1999 versus a net loss of
$8.7 million for 1998. In 1999, we reported $4.8 million pre-tax gains on the
sale of oil and gas properties. Our oil and gas production was 821 Mmcfe in 1999
compared to 1,285 Mmcfe in 1998, a decrease of 36%. Approximately 37% of this
decrease is due to the sale of properties during the first quarter of 1999. The
balance of the decrease was due to a decline in production on existing wells.
Average oil prices increased from $12.84 per barrel in 1998 to $17.54 in 1999, a
37% increase. Average natural gas prices increase from $2.15 per Mcf to $2.23, a
4% increase. As a result of the decrease in production, oil and gas revenue
decreased by $0.6 million to $2.2 million in 1999 from $2.8 million in 1998.
Our oil and gas production costs in 1999 were $1,025,947 ($1.25 per Mcfe)
compared with $1,609,733 in 1998 ($1.25 per Mcfe). The decrease in total
production expense was due primarily to the decrease in reported sales volume as
a result of the sale of properties and declining production on existing wells.
1999 production or lifting cost as a percentage of oil and gas sales decreased
to 47%, compared with 57% in 1998. This decrease was almost entirely due to
higher oil and gas prices since lifting cost per Mcfe was virtually unchanged
between the two periods as mentioned in the immediately preceding paragraph.
During the first quarter of 1999, we sold our West Virginia properties and two
producing Texas wells. Production for 1999 attributable to the properties sold
totaled 18,313 Mcf of gas. Production for 1998 attributable to the properties
sold totaled 1,566 barrels of oil and 177,830 Mcf of gas. Revenues less
operating expenses of the properties sold totaled $37,047 in 1999 and $213,784
in 1998.
During 1999, we recorded impairment expense of $0.5 million, as compared to $2.8
million recorded in 1998. Approximately 45% of the 1999 impairment was the
result of an unexpected decline in value of one of our operated properties. The
balance was due to a decline in the values of non-operated properties. The
impairment in 1998 was primarily the result of the effect of significantly lower
natural gas and crude oil prices in 1998. We review for impairment whenever
circumstances indicate that the carrying value of an asset may not be
recoverable. Such reviews were done for both 1999 and 1998. As explained above,
we follow SFAS No. 121 and recognize an impairment when the net future cash flow
that is expected to be generated by a long-lived asset is less than the net
carrying value of the asset.
Exploration expense, including geological, geophysical and seismic data
acquisition and analysis and dry hole expenses of $664,581 in 1999 decreased by
$596,976 from $1,261,557 in 1998. The decrease was due mainly to dry hole costs
of $530,358 recorded in 1998 attributable to a well drilled in West Texas and
reduced exploration activity.
Depreciation, depletion, and amortization (DDA) expense of $663,236 ($0.81 per
Mcfe) in 1999 decreased by $1,111,763 from $1,774,999 ($1.38 per Mcfe) in 1998.
Approximately 58% of the decrease was due to the decrease in sales volume, and
the balance of the decrease (42%) was attributable to lower DDA rates. The lower
DDA rates for 1999 were due to higher estimated proved reserves as a result of
using higher prices in estimating proved reserves and lower net carrying value
of our oil and gas properties as a result of prior year impairments.
During 1999, general and administrative expense of $2,291,017 decreased $883,139
from $3,174,156 in 1998. This decrease was primarily due to various cost
reduction measures implemented in late 1998 and throughout 1999. These cost
reduction measures were primarily related to reductions in the number of
employees. The 1998 amount also included cost of severance packages for former
employees.
Interest expense was $895,602 in 1999, compared to $568,085 in 1998. The
$327,517 increase was primarily due to interest on the EXCO convertible
promissory note, which we used to finance our 50% share of the EXUS Energy
properties. During 1999 we recorded interest expense of $429,333 related to the
EXCO note. Offsetting this increase was the reduction in our bank facility as a
result of the sale of the West Virginia properties and the H.E. White wells. We
applied approximately $1.7 million of the sales proceeds to our outstanding bank
debt. Interest expense includes amortization of deferred financing cost of
$29,202 in 1999 and $103,260 in 1998. The average daily balances of
interest-bearing debt was $8.3 million in 1999, compared to $4.8 million in
1998.
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ACCOUNTING POLICIES
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
No 133, Accounting for Derivative Instruments and Hedging Activities (FAS 133).
The Statement establishes accounting and reporting standards requiring that
every derivative instrument be recorded in the balance sheet as either an asset
or liability measured at fair value and that changes in fair value be recognized
currently in earnings, unless specific hedge accounting criteria are met. In
June 1999, the FASB issued Statement No. 137, Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement 133, which delays the required adoption of FAS 133 to fiscal 2001. We
will adopt SFAS No. 133 effective January 1, 2001. Under the transition
provisions of SFAS No. 133, on January 1, 2001 we will record an after-tax
cumulative-effect-type adjustment to other comprehensive income of approximately
$334,000 related to certain derivative instruments consisting principally of
commodity collar agreements covering at least fifty percent (50%) of our monthly
oil and gas production, as required by our bank lender. We have elected not to
use hedge accounting for derivatives existing at January 1, 2001. Future changes
in fair value of those derivatives will be recorded in income.
LIQUIDITY AND CAPITAL RESOURCES
At December 31, 2000, we had a working capital deficit of $2,835,202 compared
with working capital deficit of $922,899 at December 31, 1999, and a decrease in
working capital of $1,912,303. Working capital at year-end 2000 and year-end
1999 reflects classifying notes payable of $1,130,000 and $17,919,716 as
current. In 1999 we classified the notes as current because they were required
to be repaid from funds due from escrow agent and assets held for sale, both of
which were classified as current assets and relate to the sale of the EXUS
properties. The entire balance of those notes payable was repaid during the
first quarter 2000.
We believe that the higher prices we are receiving for our oil and gas, our
recent successes in the Constitution Field in Jefferson County, Texas, and the
Development Wells we plan to drill will contribute significantly to our ability
to fund our operations. We expect that we will be able to refinance our credit
facility and that the refinanced credit facility will be sufficient to provide
us with the capital to drill development wells in the Constitution Field and
four other fields. To the extent we are successful in our development drilling
activities, our borrowing base should increase, and that should fund additional
Development Wells in the more promising fields.
CURRENT CREDIT FACILITY
On May 5, 2000, we entered into a loan agreement with a new lender establishing
a $15,000,000 revolving line of credit subject to a borrowing base that will be
redetermined by the lender every six months (April 1 and October 1) based on our
oil and gas reserves, which are used as security for the loan. The interest rate
is the lender's base rate plus 1%. The interest rate on December 31, 2000, was
10.5%. At December 31, 2000, the entire balance of the revolving credit facility
has been classified as a current liability because the agreement terminates on
May 8, 2001, which is within twelve months of the balance sheet date. Although
it is our intent to refinance the outstanding balance, at this point we do not
yet have a commitment from a lender for such refinancing.
The initial borrowing base was $2.45 million, and it declined at the rate of
$50,000 per month beginning June 1, 2000. At September 30, 2000, the borrowing
base was $2.25 million. On October 1, 2000, the lender redetermined the
borrowing base to be $2.2 million, and it declined at the rate of $50,000 per
month beginning November 1, 2000 and continued to decline at that rate until the
next borrowing base redetermination on April 1, 2001, at which time, our lender
determined our borrowing base to be $1,130,000. We may request interim
redeterminations. Changes in the borrowing base are solely at the discretion of
the lender based on the lender's then current engineering standards and are
subject to the lender's credit approval process. Mandatory prepayment is
required to the extent outstanding amounts under the credit facility exceed the
borrowing base. As of April 2, 2001, we have no additional availability under
the credit facility.
We paid a facility fee of 1% of the initial borrowing base at closing. A 1/2%
facility fee will be due on all incremental increases in the borrowing base, and
a 3/8% per annum fee is due on the unused portion of the borrowing base. We are
also required to pay a $5,000 engineering fee for the initial borrowing base
determination and for each subsequent redetermination. The facility is secured
by all of our oil and gas properties, and contains usual and standard covenants
such as: debt and lien restrictions; dividend and distribution prohibitions;
prohibits cash payments to other debt holders; liquidity, leverage, net worth
and debt service coverage ratios; and financial statement reporting
requirements. The credit facility also requires that we hedge at least 50% of
our oil and gas production for twelve months. Although we believe that we will
be able to refinance our credit facility at levels that are sufficient to fund
our business plan for 2001, future availability
25
26
of credit will depend on the success of our development program and our ability
to stay in compliance with credit facility debt covenants. In the event our
current credit facility is not refinanced, we believe that we will be successful
in obtaining alternative sources of debt or equity financing.
Our current credit facility contains the following financial covenants:
(1) Consolidated tangible net worth cannot be less than 85% of consolidated
tangible net worth reported as of December 31, 1999, plus the sum of
70% of the Company's positive quarterly net income, and plus 100% of
any increase in shareholder's equity from the sale of stock in the
Company subsequent to December 31, 1999.
(2) The Company will not pay or incur, or otherwise become obligated to pay
general and administrative expenses which exceed $350,000 during any
quarter beginning with the quarter ended September 30, 2000. Non-cash
charges to general and administrative expense are excluded.
(3) The Company will maintain a current ratio of at least 1:1, with initial
calculation of such ratio to be made as of June 30, 2000. For purposes
of computing the current ratio, current maturities under the credit
facility are excluded.
(4) The Company will maintain a debt service coverage ratio of at least
1.2:1.0 with the initial calculation of such ratio to be made as of
September 30, 2000. Debt service coverage ratio is defined as the ratio
from dividing earnings before interest, taxes, depreciation, depletion
and amortization, and other non-cash charges (EBITDA) for any quarter
by debt service for such quarter.
The facility contains other usual and standard covenants such as: debt and lien
restrictions, dividend and distribution prohibitions, and financial statement
reporting requirements. At December 31, 2000 we were in default of the listed
financial covenants; however, a waiver was obtained from our lender for the
quarter ended December 31, 2000.
HEDGING ACTIVITIES
As discussed under Liquidity and Capital Resources, we obtained our current
credit facility which required us to hedge approximately one-half of our
production for a period of one year. On May 12, 2000, we entered into commodity
collar agreements for 125 barrels of oil per day for twelve months and 500 MMBtu
of gas per day for twelve months. The hedged volumes represent approximately 50%
of estimated production for the twelve month period ending May 2001. The
contract term is June 2000 through May 2001. The oil hedge is a costless collar
with a floor of $24.00 per barrel and a cap of $27.50 per barrel. If the average
NYMEX price is less than $24.00 for any month, the Company receives the
difference between $24.00 and the average NYMEX price for that particular month.
If the average NYMEX price is greater than $27.50 for any month, the Company
pays the difference between $27.50 and the average NYMEX price for that
particular month. The natural gas hedge is a costless collar with a floor of
$2.90 per MMBtu and a cap of $3.65 per MMBtu. If the indexed price of natural
gas is less than $2.90 per MMBtu for any month, the Company receives the
difference between $2.90 and the indexed price for that particular month. If the
indexed price of natural gas is greater than $3.65 per MMBtu for any month, the
Company pays the difference between $3.65 and the indexed price for that
particular month. The reference price for natural gas is the Houston Ship
Channel index for large packages as quoted by Inside Ferc. Transaction gains and
losses are determined monthly and are included in oil and gas revenues in the
period the hedged production is sold. We have determined that hedge accounting
will not be elected for our derivative positions existing at January 1, 2001.
Future changes in the fair value of those derivatives will be recorded in
income. On January 1, 2001 we will record an after-tax, cumulative-effect-type
adjustment to other comprehensive income of approximately $334,000 related to
these contracts.
26
27
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk due to fluctuations in the price of natural gas
and crude oil, as well as changes in interest rates.
Natural gas and crude oil prices fluctuate widely in response to changing market
forces, which are beyond our control. Substantially all of our revenue is from
the sale of natural gas and crude oil, so these price fluctuations can have a
significant effect on our revenue. During the second quarter 2000 we hedged
approximately 50% of our oil and natural gas production pursuant to the
requirements of our existing credit facility. On May 12, 2000 we entered into
commodity collar contracts for 125 barrels of oil per day (approximately 11,250
barrels per quarter) for 12 months and 500 MMBtu per day of gas (approximately
45,000 MMBtu per quarter) for 12 months, which approximates at least 50% of
estimated production from our existing wells for the 12 month period June 2000
through May 2001. The hedging arrangements have the effect of locking in the
effective prices we receive for the volumes hedged. For these volumes our
exposure to a significant decline in product prices is significantly reduced;
however, they also limit the benefit we might have received if prices increased
above the cap. For every $1 the NYMEX average for a month is above the $27.50
per barrel cap, the Company's net income would decrease by approximately $4,000
for the month. For every $0.10 per MMBtu the indexed price of natural gas is
above $3.65 per MMBtu for a month, the Company's net income would decrease by
approximately $2,000 for the month. While these transactions have no carrying
value, their fair value, represented by the estimated amount that would be
required to terminate them, was a loss of approximately $334,000 at December 31,
2000. We have determined that hedge accounting will not be elected for our
derivative positions existing at January 1, 2001. Future changes in the fair
value of those derivatives will be recorded in income. On January 1, 2001 we
will record an after-tax, cumulative-effect-type adjustment to other
comprehensive income of approximately $334,000 related to these contracts.
While we are required to do so under the terms of our current credit facility,
our use of these contracts has the intended impact of reducing the volatility of
our oil and gas revenues. Should the price of a commodity decline, the revenue
received from the sale of the product tends to decline to a corresponding
extent. The decline in revenue is then partially offset based on the amount of
production hedged and the hedge price. In 2000, a 10% reduction in oil and gas
prices would have reduced revenue by approximately $395,000 offset by a
reduction in hedging losses of approximately $44,000.
Changes in product prices can also have a significant effect on the value of our
oil and gas properties for purposes of determining whether an impairment
write-down must be recorded. Although impairment write-downs do not affect cash
flow, they do reduce our tangible net worth, which in turn affects our ability
to meet the tangible net worth requirements under our existing credit facility
and Nasdaq market listing requirements.
Our earnings are also affected by changes in interest rates because our bank
debt ($1,130,000 at December 31, 2000) is subject to a floating prime rate plus
1%. We plan to use significant levels of bank debt now and in the future to fund
our capital expenditures and working capital needs. Fluctuations in these rates
directly impact our interest expense. For every 1% change in the interest rate
charged by the lender, our monthly net income would change inversely by
approximately $1,000 based on the level of indebtedness in place on March 16,
2001; e.g., a 1% interest rate increase would decrease month net income by
approximately $1,000.
Historically, except when required by a lender, we have not used financial
instruments such as futures contracts or interest rate swaps to mitigate the
effect of changes in commodity prices or interest rates. We had no existing
contracts at December 31, 1999. All of our market risk sensitive instruments
were entered into for purposes other than trading.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This information appears in a separate section of this report following Part IV.
ITEM 9. CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
27
28
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be set forth under the captions
"Election of Directors," "Section 16(a) Beneficial Ownership Reporting
Compliance," and "Management and Remuneration" of our proxy statement for our
2001 Annual Meeting of Shareholders (the "Proxy Statement"), which will be filed
with the Commission pursuant to Regulation 14A under the Exchange Act and is
incorporated herein by reference. The Proxy Statement is expected to be filed
prior to April 30, 2001.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is set forth under the caption Executive
Compensation Summary under "Management and Remuneration" of our Proxy Statement,
which will be filed with the Commission pursuant to Regulation 14A under the
Exchange Act and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is set forth under the caption "Ownership
of Securities" of our Proxy Statement, which will be filed with the Commission
pursuant to Regulation 14A under the Exchange Act and is incorporated herein by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is set forth under the captions
"Management and Remuneration" - Director Compensation and Certain Relationships
and Related Party Transactions" of our Proxy Statement, which will be filed with
the Commission pursuant to Regulation 14A under the Exchange Act and is
incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Annual Report on Form
10-K:
1. FINANCIAL STATEMENTS
See Index to Financial Statements on page F-1 to this Annual Report on Form
10-K.
2. FINANCIAL STATEMENT SCHEDULES
All schedules are omitted because the information is not required under the
related instructions or is inapplicable or because the information is included
in the Financial Statements or related Notes.
3. EXHIBITS
*3.1 Articles of Incorporation of Venus Exploration, Inc. (incorporated by
reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
*3.2 Bylaws of Venus Exploration, Inc., as amended (incorporated by
reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
*4.1 Warrant to purchase Common Stock issued to Martin A. Bell (incorporated
by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
28
29
*4.2 Form of Registration Rights Agreement between Venus Exploration, Inc.
and various holders of 7% Convertible Subordinated Notes (incorporated
by reference to Exhibit 10.5 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 1999)
*+4.3 Form of Salary Reduction Stock Option Agreement (incorporated by
reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 1999)
*+10.1 Registrant's 1985 Incentive Stock Option Plan (incorporated by
reference to Exhibit 10.12 to the Company Registration Statement on
Form S-4 (File No. 33-1903) declared effective January 8, 1986)
*+10.2 Registrant's 1995 Incentive Stock Option Plan (incorporated by
reference to Exhibit 10.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995)
+10.3 1997 Incentive Plan, as amended and restated (filed herewith)
*10.4 Letter Agreement dated February 4, 1999, between Venus Exploration,
Inc., and Petroleum Development Corporation (incorporated by reference
to Exhibit 2.1 to the Company's Current Report on Form 8-K filed
February 26, 1999)
*10.5 Amendment to Letter Agreement dated February 11, 1999, between Venus
Exploration, Inc., and Petroleum Development Corporation (incorporated
by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K
filed February 26, 1999)
*+10.6 Executive Employment Agreement dated July 1, 1999, for E.L. Ames, Jr.
(incorporated by reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30, 1999)
*10.7 Registration Rights Agreement dated November 30, 1998 between Venus
Exploration, Inc. and Stratum Group, L.P. (incorporated by reference to
Exhibit 4.4 to the Company's Registration Statement on Form S-3 (File
No. 333-73457) filed March 5, 1999)
*10.8 Purchase and Sale Agreement between Apache Corporation as seller, and
Venus Exploration, Inc., buyer, dated May 13, 1999 (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K
filed July 15, 1999)
*10.9 Credit Agreement among EXUS Energy, LLC, as borrower, NationsBank,
N.A., as administrative agent, and financial institutions listed on
Schedule I, dated June 30, 1999 (incorporated by reference to Exhibit
10.2 to the Company's Current Report on Form 8-K filed July 15, 1999)
*10.10 Limited Liability Company Agreement of EXUS Energy, LLC, dated June 30,
1999 (incorporated by reference to Exhibit 10.3 to the Company's
Current Report on Form 8-K filed July 5, 1999)
*10.11 Convertible Promissory Note made by Venus Exploration, Inc. in favor of
EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to
Exhibit 10.4 to the Company's Current Report on Form 8-K filed July 15,
1999)
*10.12 Pledge Agreement made by Venus Exploration, Inc. for the benefit of
EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to
Exhibit 10.5 to the Company's Current Report on Form 8-K filed July 15,
1999)
*10.13 Registration Rights Agreement between EXCO Resources, Inc. and Venus
Exploration, Inc., dated June 30, 1999 (incorporated by reference to
Exhibit 10.6 to the Company's Current Report on Form 8-K filed July 15,
1999)
*10.14 Agreement Among Members between EXCO Resources Inc., dated June 30,
1999 (incorporated by reference to Exhibit 10.7 to the Company's
Current Report on Form 8-K filed July 15, 1999)
29
30
*10.15 Purchase and Sale Agreement between Venus Exploration, Inc. as seller,
and Anadarko Petroleum Corporation, as buyer, dated December 17, 1999
(incorporated by reference to Exhibit 10.1 to the Company's Current
Report on Form 8-K filed July 18, 2000)
*10.16 Amendment to Purchase and Sale Agreement dated December 17, 1999,
between Venus Exploration, Inc. as seller, and Anadarko Petroleum
Corporation., buyer, dated December 31, 1999 (incorporated by reference
to Exhibit 10.31 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000)
+10.17 Consulting Agreement effective October 30, 2000, between Venus
Exploration, Inc. and P. Mark Stark (filed herewith)
*21.1 List of Subsidiaries (incorporated by reference to Exhibit 21 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1997)
23.1 Consent of KPMG LLP regarding incorporation by reference (filed
herewith)
23.2 Consent of Ryder Scott Company regarding incorporation by reference
(filed herewith)
- ----------
* Incorporated herein by reference.
+ Management contract or compensatory plan or arrangement.
(b) Reports on Form 8-K.
None.
(c) Exhibits.
See the list of exhibits filed as part of this Form 10-K listed under
sub-item (a) 3 above.
(d) No financial statement schedules are required to be filed herewith. See
sub-item (a) 2 above.
30
31
SIGNATURE PAGE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized in the City of San Antonio,
Texas, on the 12th day of April, 2001.
VENUS EXPLORATION, INC.
By: /s/ EUGENE L. AMES, JR.
--------------------------
Eugene L. Ames, Jr.
Chairman of the Board of Directors
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
DATE TITLE SIGNATURE
April 12, 2001 Chairman of the Board of Directors /s/ EUGENE L. AMES, JR.
and Chief Executive Officer -----------------------------------
Eugene L. Ames, Jr.
April 12, 2001 President, Director and Chief /s/ JOHN Y. AMES
Operating Officer -----------------------------------
John Y. Ames
April 12, 2001 Chief Financial Officer /s/ P. MARK STARK
(Principal Financial Officer) -----------------------------------
P. Mark Stark
April 12, 2001 Chief Accounting Officer /s/ TERRY F. HARDEMAN
(Principal Accounting Officer) -----------------------------------
Terry F. Hardeman
April 12, 2001 Majority of the Directors of the /s/ MARTIN A. BELL
Registrant (including Eugene L. -----------------------------------
Ames, Jr. and John Y. Ames) Martin A. Bell
April 12, 2001 Majority of the Directors of the /s/ JERE W. MCKENNY
Registrant (including Eugene L. -----------------------------------
Ames, Jr. and John Y. Ames) Jere W. McKenny
April 12, 2001 Majority of the Directors of the /s/ J.C. ANDERSON
Registrant (including Eugene L. -----------------------------------
Ames, Jr. and John Y. Ames) J.C. Anderson
31
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
VENUS EXPLORATION, INC. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
Independent Auditors' Report F-2
Consolidated Balance Sheets as of
December 31, 2000 and 1999 F-3
Consolidated Statements of Operations for
Each of the years in the three-year period
Ended December 31, 2000 F-4
Consolidated Statements of Shareholders' Equity and Comprehensive
Income for each of the years in the three-year period
Ended December 31, 2000 F-5
Consolidated Statements of Cash Flows for each of the
Years in the three-year period ended December 31, 2000 F-6
Notes to Consolidated Financial Statements F-7
F-1
33
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders of
Venus Exploration, Inc.:
We have audited the accompanying consolidated balance sheets of Venus
Exploration, Inc. and subsidiary as of December 31, 2000 and 1999, and the
related consolidated statements of operations, shareholders' equity and
comprehensive income, and cash flows for each of the years in the three-year
period ended December 31, 2000. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Venus Exploration,
Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2000, in conformity with accounting principles generally
accepted in the United States of America.
KPMG LLP
March 28, 2001, except as to note 16,
which is as of April 10, 2001
San Antonio, Texas
F-2
34
VENUS EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
----------------------------
2000 1999
------------ ------------
ASSETS
Current assets:
Cash and equivalents $ 1,086,035 $ 235,673
Trade accounts receivable 1,034,375 717,964
Funds due from escrow agent -- 17,303,582
Assets held for sale -- 1,236,030
Prepaid expenses and other 73,461 90,177
------------ ------------
Total current assets 2,193,871 19,583,426
Oil and gas properties and equipment, at cost
under the successful efforts method, net 4,783,125 4,300,876
Other property and equipment, net 93,644 136,274
Deferred financing costs, at cost less accumulated amortization 30,813 20,380
Other assets, at cost less accumulated amortization 15,730 423,750
------------ ------------
$ 7,117,183 $ 24,464,706
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable $ 3,435,011 $ 1,447,920
Other liabilities 464,062 1,138,689
Current notes payable 1,130,000 17,919,716
------------ ------------
Total current liabilities 5,029,073 20,506,325
Long-term debt -- 1,750,000
Other long-term liabilities 13,085 18,131
------------ ------------
Total liabilities 5,042,158 22,274,456
Shareholders' equity:
Preferred stock; par value of $0.01; 5,000,000 shares
authorized; none issued and outstanding -- --
Common stock; par value of $.01; 50,00,000 shares
authorized; 12,341,065 and 11,055,285 shares issued,
and 12,314,185 and 11,055,285 shares outstanding in 2000
and 1999, respectively 123,411 110,553
Additional paid-in capital 18,721,312 17,336,593
Accumulated deficit (16,710,706) (15,194,396)
Less cost of treasury stock (26,880 shares) (40,242) --
Accumulated other comprehensive income - net unrealized
appreciation on investment securities -- 68,750
Unearned compensation (18,750) (131,250)
------------ ------------
Total shareholders' equity 2,075,025 2,190,250
Commitments and contingencies
------------ ------------
$ 7,117,183 $ 24,464,706
============ ============
See accompanying notes to consolidated financial statements.
F-3
35
VENUS EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31,
--------------------------------------------
2000 1999 1998
------------ ------------ ------------
Oil and gas revenues $ 3,718,364 $ 2,183,681 $ 2,804,749
------------ ------------ ------------
Costs of operations:
Production expense 1,456,334 1,025,947 1,609,733
Exploration expenses, including dry holes 1,159,132 664,581 1,261,557
Impairment of oil and gas properties -- 544,740 2,803,152
Depreciation, depletion and amortization 694,743 663,236 1,774,999
General and administrative 1,894,204 2,291,017 3,174,156
------------ ------------ ------------
Total expenses 5,204,413 5,189,521 10,623,597
------------ ------------ ------------
Operating loss (1,486,049) (3,005,840) (7,818,848)
------------ ------------ ------------
Other income (expense):
Interest expense (169,217) (895,602) (568,085)
Equity in net earnings from EXUS Energy, LLC -- 444,968 --
Debt conversion expense (235,451) -- --
Gain on sale of assets 598,502 4,762,170 30,007
Interest and other income 25,905 33,888 32,502
------------ ------------ ------------
219,739 4,345,424 (505,576)
------------ ------------ ------------
Net income (loss) before income taxes and extraordinary
item (1,266,310) 1,339,584 (8,324,424)
Income tax expense -- 330,000 --
------------ ------------ ------------
Income (loss) before extraordinary item (1,266,310) 1,009,584 (8,324,424)
Extraordinary loss on early extinguishment of debt (250,000) -- (345,905)
------------ ------------ ------------
Net income (loss) $ (1,516,310) $ 1,009,584 $ (8,670,329)
============ ============ ============
Basic and diluted earnings (loss) per share:
Earnings (loss) before extraordinary item $ (.11) $ 0.09 $ (0.84)
Extraordinary loss on early extinguishment of debt (.02) $ -- (0.03)
------------ ------------ ------------
Earnings (loss) $ (.13) $ 0.09 $ (0.87)
============ ============ ============
Common shares and equivalents outstanding:
Basic 11,666,444 11,011,218 9,934,251
============ ============ ============
Diluted 11,666,444 11,579,723 9,934,251
============ ============ ============
See accompanying notes to consolidated financial statements.
F-4
36
VENUS EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME
Accumu-
lated
other
Additional Retained Compre-
Issued Common Paid-in Treasury Earnings hensive Unearned
shares Stock capital Stock (deficit) Income Compensation Total
------------ --------- ------------ ---------- ------------ ----------- ------------ -----------
Balances, 9,736,815 $ 97,368 $ 15,010,189 -- $ (7,533,651) $ -- $ -- $ 7,573,906
December 31, 1997
Net loss -- -- -- -- (8,670,329) -- -- (8,670,329)
Stock issued for -- --
Stratum settlement 1,100,000 11,000 1,756,500 -- -- -- -- 1,767,500
Compensation cost
for stock and
stock options 134,510 1,345 442,353 -- -- -- (337,500) 106,198
Earned compensation -- -- -- -- -- -- 93,750 93,750
------------ --------- ------------ ---------- ------------ ----------- ------------ -----------
Balances, 10,971,325 109,713 17,209,042 -- (16,203,980) -- (243,750) 871,025
December 31, 1998
Net income -- -- -- -- 1,009,584 -- -- 1,009,584
Net unrealized
change in
investment
securities -- -- -- -- -- 68,750 -- 68,750
-----------
Comprehensive income -- -- -- -- -- -- -- 1,078,334
Compensation cost
for stock and
stock options 62,536 626 100,644 -- -- -- -- 101,270
Interest paid with
common stock 21,424 214 26,907 -- -- -- -- 27,121
Earned compensation -- -- -- -- -- -- 112,500 112,500
------------ --------- ------------ ---------- ------------ ----------- ------------ -----------
Balances,
December 31, 1999 11,055,285 110,553 17,336,593 -- (15,194,396) 68,750 (131,250) 2,190,250
Net Loss -- -- -- -- (1,516,310) -- -- (1,516,310)
Net unrealized
change included
in net income -- -- -- -- -- (68,750) -- (68,750)
-----------
Comprehensive
income (loss) (1,585,060)
Treasury stock -
26,880 shares
purchased -- -- -- (40,242) -- -- -- (40,242)
Compensation cost
for stock and
stock options 79,873 799 112,347 -- -- -- -- 113,146
Interest paid with
common stock 63,053 630 54,920 -- -- -- -- 55,550
Convertible
subordinated
notes converted 1,142,854 11,429 1,217,452 -- -- -- -- 1,228,881
to common stock
Earned compensation -- -- -- -- -- -- 112,500 112,500
------------ --------- ------------ ---------- ------------ ----------- ------------ -----------
Balances,
December 31, 2000 12,341,065 $ 123,411 $ 18,721,312 $ (40,242) $(16,710,706) $ -- $ (18,750) $ 2,075,025
============ ========= ============ ========== ============ =========== ============ ===========
See accompanying notes to consolidated financial statements.
F-5
37
VENUS EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31,
--------------------------------------------
2000 1999 1998
------------ ------------ ------------
Operating Activities:
Net earnings (loss) $ (1,516,310) $ 1,009,584 $ (8,670,329)
Adjustments to reconcile net loss to net cash
used in operating activities:
Depreciation, depletion and amortization
of oil and gas properties 694,743 663,236 1,774,999
Other depreciation and amortization 151,181 147,388 263,985
Impairments, abandoned leases, and dry
hole costs 195,864 593,470 3,350,260
Gain on sale of property and equipment (598,502) (4,762,170) (30,007)
Debt and option conversion expense 228,881 -- --
Equity in net earnings of EXUS -- (444,968) --
Loss on early extinguishment of debt 250,000 -- 345,905
Compensation expense for stock and stock
options 225,647 213,770 161,198
Interest expense paid with common stock 55,550 27,121 --
Deferred interest expense on EXCO note (71,556) 71,556 --
Changes in operating assets and
liabilities:
Trade accounts receivable (316,411) (303,269) 1,853,803
Prepaid expenses and other 986 (12,878) 27,668
Trade accounts payable 1,987,092 179,177 (1,793,957)
Advances from interest owners -- -- (17,862)
Other liabilities (603,071) 633,577 206,777
------------ ------------ ------------
Net cash provided by (used in)
operating activities 684,094 (1,984,406) (2,527,560)
------------ ------------ ------------
Investing Activities:
Capital expenditures (1,542,891) (584,815) (3,271,352)
Investment in EXUS -- (7,450,806) --
Distributions from EXUS 250,000 493,839 --
Proceeds from sales of property and equipment 19,376,964 2,641,129 160,733
------------ ------------ ------------
Net cash provided by (used in)
investing activities 18,084,073 (4,900,653) (3,110,619)
------------ ------------ ------------
Financing Activities:
Net proceeds from issuance of long-term debt
and notes payable 3,678,609 9,063,495 7,492,202
Principal payments on long-term debt and notes
payable (21,223,371) (2,038,239) (2,355,832)
Deferred financing costs (82,801) (30,356) (76,045)
Proceeds from issuance of stock -- -- 21,250
Prepayment penalty on early extinguishment of debt (250,000) -- --
Purchase of treasury stock (40,242) -- --
------------ ------------ ------------
Net cash provided by (used in) financing
activities (17,917,805) 6,994,900 5,081,575
------------ ------------ ------------
Increase (decrease) in cash and equivalents 850,362 109,841 (556,604)
Cash and equivalents, beginning of year 235,673 125,832 682,436
------------ ------------ ------------
Cash and equivalents, end of year $ 1,086,035 $ 235,673 $ 125,832
============ ============ ============
See accompanying notes to consolidated financial statements.
F-6
38
VENUS EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2000 AND 1999
(1) ORGANIZATION AND BUSINESS COMBINATION
Venus Exploration, Inc. (the Company) is primarily engaged in the business
of exploring for, acquiring, developing and operating onshore oil and gas
properties in the United States. The Company presently has oil and gas
properties, acreage and production in eight states.
The Company is the result of a merger which occurred on May 21, 1997. Xplor
Corporation acquired the assets of Venus in a reverse acquisition. After
the transaction, the Company's name was changed from Xplor Corporation to
Venus Exploration, Inc.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Principles of Consolidation
The consolidated financial statements include the financial statements
of Venus Exploration, Inc. and its wholly-owned subsidiary. All
significant intercompany balances and transactions have been eliminated
in consolidation.
(b) Cash and Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less when purchased and money market
accounts to be cash equivalents.
(c) Oil and Gas Properties
The Company uses the successful efforts method of accounting for its
oil and gas operations. Under this method, the costs of unproved leases
and exploratory wells are initially capitalized pending the results of
exploration efforts. The costs of unproved properties are assessed
periodically for impairment, on a field-by-field basis, and a loss is
recognized to the extent, if any, that the cost of a property has been
impaired. Exploration expenses, including geological and geophysical
costs, delay rentals, and dry hole costs are charged to expense as
incurred. Exploratory drilling costs are initially capitalized, but are
charged to expense if and when the well is determined to be
unsuccessful.
As unproved properties are determined to be productive, the property
acquisition costs and related exploratory drilling costs of successful
wells are transferred to proved properties. Development costs of proved
properties, including producing wells and related facilities and any
development dry holes, are capitalized. Depletion of the costs of
proved properties are provided by the unit-of-production method based
upon estimates of proved oil and gas reserves on a field-by-field
basis.
Capitalized costs of proved properties are periodically reviewed for
impairment on a field-by-field basis, and, if necessary, an impairment
provision is recognized to reduce the net carrying amount of such
properties to their estimated fair values generally determined on a
discounted cash flow basis. In determining if an impairment is
necessary, the Company estimates future cash flows based on proved
reserves and its estimate of future commodity prices to determine if
the carrying amount of the property is in excess of its estimated
undiscounted future cash flows. The Company's current future price
assumption is based on New York Mercantile Exchange ("NYMEX") futures
pricing of crude oil and natural gas contracts.
F-7
39
(d) Other Property and Equipment
Depreciation and amortization of transportation equipment and office
furniture, fixtures, equipment, and leasehold improvements are computed
using the straight-line method over the respective estimated useful
lives. Maintenance, repairs and renewals are charged to operations,
except that renewals which extend the life of the property are
capitalized.
(e) Income Taxes
The Company follows the asset and liability method of accounting for
income taxes. Under this method, deferred tax assets and liabilities
are recognized for the estimated future tax effects of temporary
differences between the financial statement carrying amounts of
existing assets and liabilities and their respective tax basis.
Deferred tax assets and liabilities are measured using enacted tax
rates in effect for the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax assets
and liabilities of a change in tax laws or rates is recognized in
income in the period that includes the enactment date.
(f) Revenue Recognition
The Company records revenue for oil sales when the oil is sold. The
Company records revenue following the entitlement method of accounting
for gas imbalances. As of December 31, 2000 and 1999, there were no
significant imbalances. Three customers accounted for approximately
26%, 13% and 10% of total consolidated revenues for the year ended
December 31, 2000. Three customers accounted for approximately 19%, 13%
and 8% of total consolidated revenues for the year ended December 31,
1999. Three customers accounted for approximately 16%, 13% and 12% of
total consolidated revenues for the year ended December 31, 1998.
(g) Deferred Financing Costs
Deferred financing costs consist of costs associated with obtaining the
Company's debt agreements, as discussed in Note 6, which are amortized
over the expected term of the related borrowings.
(h) Hedging Transactions
As required by its bank lender, the Company enters into commodity
derivative contracts for non-trading purposes as a hedging strategy to
manage commodity prices associated with oil and gas sales and to reduce
the impact of price fluctuations.
The Company utilizes the hedge or deferral method of accounting for
commodity derivative financial instruments whereby gains and losses on
these hedging instruments are recognized and recorded as revenues on
the statement of operations when the related natural gas or oil has
been produced, purchased or delivered. As a result, gains and losses on
commodity financial instruments are generally offset by similar changes
in the realized prices of natural gas and crude oil. To qualify as
hedging instruments, these instruments must be highly correlated to
anticipated future sales such that the Company's exposure to the risks
of commodity price changes is reduced. While commodity financial
instruments are intended to reduce the Company's exposure to declines
in the market price of natural gas and crude oil, the commodity
financial instruments may also limit the Company's gain from increases
in the market price of natural gas and crude oil.
On May 12, 2000, the Company entered into hedge contracts for 125
barrels of oil per day for twelve months (or 45,625 barrels) and 500
mmbtu per day for twelve months (or 182,500 mmbtu). The hedge term is
June 2000 through May 2001. The oil hedge is a costless collar with a
floor of $24.00 per barrel and a cap of $27.50 per barrel. The natural
gas hedge is a costless collar with a floor of $2.90 per mmbtu and a
cap of $3.65 per mmbtu. The reference price for oil is the New York
Mercantile Exchange West Texas Intermediate future contract. For
natural gas the index price is the Houston Ship Channel index for large
packages as quoted by Inside Ferc. As of December 31, 2000, the
estimated fair value of the Company's positions was a net payable of
approximately $334,000 based upon an estimate of what the Company would
owe if the contracts were liquidated.
F-8
40
(i) Stock-Based Compensation
Financial Accounting Standards Board Statement No. 123, Accounting for
Stock-Based Compensation, allows companies to adopt a fair value based
method of accounting for stock-based employee compensation plans or to
continue to use the intrinsic-value based method of accounting
prescribed by Accounting Principles Board ("APB") Opinion No. 25,
Accounting for Stock Issued to Employees. The Company has elected to
continue to account for stock-based compensation under the
intrinsic-value method under the provisions of APB Opinion No. 25 and
related interpretations. Under this method, compensation expense is
recognized for stock options when the exercise price of the options is
less than the current market value of the underlying stock on the date
of grant.
(j) Use of Estimates
The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets
and liabilities and disclosure of contingent assets and liabilities at
the date of the consolidated financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
(k) Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments,
litigation, fines, and penalties are recorded when it is probable that
a liability has been incurred and that the related amount can be
reasonably estimated.
(l) Fair Values of Financial Instruments
The Company's financial instruments consist primarily of short-term
trade receivables or payables or issued debt instruments with floating
interest rates for which management believes fair value approximates
carrying value.
(m) Concentration of Credit Risk
Financial instruments which potentially subject the Company to
concentrations of credit risk consist primarily of temporary cash
investments and trade receivables. The Company places its temporary
cash investments in U.S. Government securities and in other high
quality financial instruments. The Company's customer base consists
primarily of independent oil and natural gas producers and purchasers
of oil and gas products.
(n) Earnings (loss) per share
The Company follows Statement of Financial Accounting Standards ("FAS")
No. 128, "Earnings Per Share" under which basic net earnings (loss) per
common share is computed by dividing net loss by the weighted average
number of common shares outstanding. Diluted earnings (loss) per share
is computed by assuming the issuance of common shares for all dilutive
potential common shares outstanding.
In 1998 and 2000 the Company reported net losses therefore basic and
diluted earnings per share are not presented. In 1999 basic and diluted
earnings per share were calculated as follows.
F-9
41
1999
------------
Basic earnings per share:
Net income available to common shareholders (numerator) $ 1,009,584
Weighted average common shares outstanding (denominator) 11,011,218
------------
Earnings per share $ 0.09
============
Diluted earnings per share:
Net income available to common shareholders $ 1,009,584
Interest paid to convertible note holders 44,771
------------
Net income available to common shareholders plus assumed conversions (numerator) $ 1,054,355
============
Weighted average common shares outstanding 11,011,218
Effect of dilutive securities:
Conversion of convertible subordinated notes 556,163
Assumed exercise of dilutive stock options and warrants 19,694
Less common shares issued to pay interest (7,352)
------------
Weighted average common shares outstanding plus assumed conversions (denominator) 11,579,723
============
Diluted earnings per share $ 0.09
============
(o) New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement No 133, Accounting for Derivative Instruments and Hedging
Activities (FAS 133). The Statement establishes accounting and
reporting standards requiring that every derivative instrument be
recorded in the balance sheet as either an asset or liability measured
at fair value and that changes in fair value be recognized currently in
earnings, unless specific hedge accounting criteria are met. In June
1999, the FASB issued Statement No. 137, Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of
FASB Statement 133, which delays the required adoption of FAS 133 to
fiscal 2001. The Company will adopt SFAS No. 133 effective January 1,
2001. Under the transition provisions of SFAS No. 133, on January 1,
2001 the Company will record an after-tax cumulative-effect-type
adjustment to other comprehensive income of approximately $334,000
related to certain derivative instruments consisting principally of
commodity collar agreements covering at least fifty percent (50%) of
its monthly oil and gas production. The Company has determined that
hedge accounting will not be elected for derivatives existing at
January 1, 2001. Future changes in fair value of those derivatives will
be recorded in income.
F-10
42
(3) ACQUISITIONS AND DISPOSITIONS
On June 30, 1999, EXUS, owned 50% by the Company and 50% by EXCO Resources,
Inc. (EXCO), completed the acquisition of certain oil and natural gas
producing properties located in Jackson Parish, Louisiana (the EXUS
Properties). The purchase price, after closing adjustments, was $27.6
million. EXUS funded the acquisition with $14 million drawn under a new
bank credit facility it established, and $14 million of EXUS equity capital
which consisted of $7 million cash contribution each by the Company and
EXCO. The Company's capital was funded by a $7 million convertible
promissory note in favor of EXCO dated June 30, 1999.
On December 31, 1999 the Company sold its entire 50% share of the EXUS
Properties. To effect the sale, EXUS distributed the EXUS Properties to
Venus and EXCO, and Venus and EXCO then sold their undivided interest on
December 31, 1999, resulting in a pre-tax gain of $4.7 million to the
Company, of which $4.3 million was recorded in 1999 and the remaining $0.4
million was recorded in the first quarter 2000 when contingencies related
to part of the properties sold were cleared. The Company recorded
approximately $445,000 in equity in net earnings from EXUS during the six
months it owned the investment. In addition, the Company reported
approximately $360,000 in currently due interest related to the EXCO note
and $72,000 in deferred interest.
(4) OIL AND GAS PROPERTIES
Oil and gas properties consist of the following at December 31, 2000 and
1999:
2000 1999
------------ -----------
Proved properties $ 8,685,387 $ 8,058,806
Unproved properties 116,360 267,298
------------ -----------
8,801,747 8,326,104
Less accumulated depreciation, depletion and amortization (4,018,622) (4,025,228)
------------ -----------
$ 4,783,125 $ 4,300,876
============ ===========
The impairment of oil and gas properties recognized in 1999 includes a
write-down of proved properties of approximately $544,740 (none in 2000).
Impairment is recognized only if the carrying amount of a property is
greater than its expected future cash flows based on proved reserves and
estimated future commodity prices. The amount of the impairment is based on
the estimated fair value of the property.
(5) OTHER PROPERTY AND EQUIPMENT
Other property and equipment consists of the following at December 31, 2000
and 1999:
2000 1999
------------ -----------
Transportation equipment $ 6,293 $ 6,293
Furniture, fixtures and office equipment 556,234 523,430
Geophysical interpretation system 118,516 118,516
------------ -----------
681,043 648,239
Less accumulated depreciation, depletion and amortization (587,399) (511,965)
------------ -----------
$ 93,644 $ 136,274
============ ===========
F-11
43
(6) LONG-TERM DEBT AND NOTES PAYABLE
Long-term debt consists of the following at December 31, 2000 and 1999:
2000 1999
------------ ------------
7% Convertible subordinated promissory notes $ -- $ 1,000,000
Subordinated debenture -- 750,000
------------ ------------
$ -- $ 1,750,000
============ ============
Notes payable consists of the following at December 31, 2000 and 1999:
2000 1999
------------ ------------
Revolving credit $ 1,130,000 $ 3,819,716
EXCO Convertible Note -- 7,000,000
NationsBank, N. A. Credit Facility -- 7,100,000
------------ ------------
$ 1,130,000 $ 17,919,716
============ ============
7% Convertible Subordinated Promissory Notes
In the second quarter of 1999, the Company completed the private placement
to six investors (including one director of the Company and one person who
was later appointed a director of the Company) of six unsecured convertible
subordinated promissory notes (the "Subordinated Notes") totaling
$1,000,000. The net proceeds to the Company were $975,000 after legal fees
associated with the transaction. The Company used the proceeds to fund
working capital.
The interest rate on the Subordinated Notes was 7% per annum, and at the
option of the Company the interest was payable in the Company's common
stock. During 1999 the Company paid interest for the quarters ended June
30, 1999, and September 30, 1999, with 21,424 shares of the Company's
common stock. In January 2000 the Company issued 15,731 shares in payment
of the interest due for the quarter ended December 31, 1999, and the
Company subsequently issued 47,322 shares in payment of the interest due
for the quarters ended March 31, 2000, June 30, 2000, and September 30,
2000.
The Subordinated Notes were to mature in 2004, and the noteholders had the
option to convert the debt into the Company's common stock at any time, at
a conversion price of $1.15 per share, the market value of the common stock
on the date the terms were agreed to. On June 30, 2000, five of the six
noteholders agreed to convert the original principal amount of their debt
holdings, $700,000, into 799,997 shares of the Company's common stock
pursuant to an offer by the Company to induce conversion. The Company
offered the noteholders the opportunity, until June 30, 2000, to convert
the Subordinated Notes at a conversion price of $0.875 per share. The lower
conversion price of $0.875 per share resulted in 191,303 additional shares
being issued than would have been issued under the original conversion
price of $1.15 per share. During the quarter ended June 30, 2000, the
Company recorded $167,000 in non-cash debt conversion expense related to
the fair value of the 191,303 additional shares issued. The Company also
incurred $7,000 of legal cost related to the debt conversion.
During the quarter ended September 30, 2000, the Company extended the
inducement to convert option to August 31, 2000. On August 22, 2000, the
remaining noteholder elected to convert his debt holdings, $300,000, into
342,857 shares of the Company's common stock, which included 81,987
additional shares due to the reduced conversion price. The Company recorded
$61,000 in non-cash debt conversion expense related to the fair value of
the 81,987 additional shares issued.
Subordinated Debenture
During October 1999, the chief executive officer of the Company advanced
the Company $750,000 in exchange for a Subordinated Debenture (the
"Debenture") issued by the Company. The net proceeds to the
F-12
44
Company were approximately $730,000 after legal and other costs associated
with the transaction. The Company used the proceeds to fund working
capital. On May 12, 2000, the Debenture was repaid in full from proceeds
drawn from the new bank credit facility.
Revolving Credit
As of December 31, 1999, the Company had a revolving line of credit subject
to a borrowing base determined by the bank based on the Company's oil and
gas reserves which were used as security for the loan. The interest rate at
December 31, 1999 was 9.50%. On January 6, 2000, as part of the cash
settlement from the sale of the Company's interest in the EXUS Properties,
$3,716,000 was used to reduce the outstanding balance under the credit
facility, resulting in a outstanding loan balance of $152,000 as of January
6, 2000. On March 30, 2000, the outstanding balance under the credit
facility was repaid.
EXCO Convertible Note
On June 30, 1999, the Company borrowed $7 million from EXCO under the terms
of an $8 million convertible promissory note (the "EXCO Note") due July 1,
2004. The Company drew $7 million under the EXCO Note to fund its capital
contribution to EXUS and the entire amount was repaid on January 6, 2000,
from proceeds from the escrow account created on December 31, 1999, when
the EXUS Energy properties were sold. There was no conversion of any part
of the EXCO Note into common shares before its termination, and interest
during the actual term outstanding was 10%.
The EXCO Note contained a prepayment penalty provision of 3.57% of the
principal prepaid for any prepayment occurring on or before July 1, 2000.
On January 6, 2000, the Company paid a $250,000 prepayment penalty when it
prepaid the entire $7 million outstanding balance. During the first quarter
of 2000 the Company recognized an extraordinary loss for the amount of the
prepayment penalty. In addition, the Company recorded a reversal of $70,000
in accrued imputed interest that did not have to be paid because of the
prepayment.
NationsBank, N.A. Credit Facility
In connection with EXUS' acquisition of the properties in Jackson Parish,
Louisiana, on June 30, 1999, EXUS entered into a credit facility with
NationsBank, N.A. as administrative agent and lender. The credit facility,
which was due to mature on June 30, 2002, provided for borrowings up to $50
million, subject to borrowing base limitations. The borrowing base at
December 31, 1999 totaled $19.5 million, of which $14.2 million was
outstanding. On December 31, 1999 EXUS distributed the credit facility and
EXUS' oil and gas properties to Venus and EXCO so that Venus and EXCO could
sell the properties on December 31, 1999. Venus' share of the outstanding
balance under the credit facility at December 31, 1999, totaled $7.1
million and the entire balance was repaid on January 6, 2000, from proceeds
from the escrow account created on December 31, 1999, when the oil and gas
properties were sold.
Bank One
On May 5, 2000, the Company entered into a loan agreement with a new bank
establishing a $15,000,000 revolving line of credit subject to a borrowing
base determined every six months (March 1 and September 1) by the bank
based on the Company's oil and gas reserves which are used as security for
the loan. The interest rate is the bank's base rate plus 1%. The interest
rate on December 31, 2000, was 10.5%. The revolving credit facility has
been classified as a current liability because the agreement terminates on
May 8, 2001. Although it is the Company's intent to refinance the
outstanding balance, at this point the Company has not yet obtained a
commitment from a lender for such refinancing.
The initial borrowing base was $2.45 million and it declined at the rate of
$50,000 per month beginning June 1, 2000. On October 1, 2000, the lender
determined the borrowing base to be $2.2 million, and it declined at the
rate of $50,000 per month beginning November 1, 2000 and will continue
until the next borrowing base redetermination on April 1, 2001. The Company
may request interim redeterminations. Changes in the borrowing base are
solely at the discretion of the lender based on the lender's then current
engineering
F-13
45
standards and are subject to the lender's credit approval process.
Mandatory prepayment is required to the extent outstanding amounts under
the credit facility exceed the borrowing base.
A facility fee of 1% of the initial borrowing base was paid at closing. A
1/2% facility fee will be due on all incremental increases in the borrowing
base, and a 3/8% per annum fee is due on the unused portion of the
borrowing base. The Company is also required to pay a $5,000 engineering
fee for the initial borrowing base determination and for each subsequent
redetermination. The facility is secured by all of the Company's oil and
gas properties, and contains usual and standard covenants such as: debt and
lien restrictions; dividend and distribution prohibitions; prohibits cash
payments to other debtholders; liquidity, leverage, net worth and debt
service coverage ratios; and financial statement reporting requirements.
The credit facility also requires that the Company hedge at least 50% of
its oil and gas production for twelve months. The Company is in compliance
with or has obtained waiver of these covenants as of December 31, 2000.
(7) INCOME TAXES
No provision for federal income taxes has been recorded in the accompanying
financial statements for the year ended December 31, 2000 due to the losses
recorded by the Company. For the year ended December 31, 1999, no provision
was recorded due to the availability of net operating loss carryforwards.
The tax provision for the year ended December 31, 1999 consists solely of
state income taxes due to the sale of oil and gas properties.
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31, 2000 and 1999 are presented below:
2000 1999
----------- -----------
Deferred tax assets:
Oil and gas and other property and
equipment, principally due to differences
in depreciation, depletion, and amortization $ 241,000 $ 648,000
Net operating loss carryforwards 4,255,000 3,401,000
Depletion carryforwards 330,000 96,000
Other 16,000 28,000
----------- -----------
Total gross deferred tax assets 4,842,000 4,173,000
Less valuation allowance (4,842,000) (4,173,000)
----------- -----------
Net deferred tax assets $ -- $ --
=========== ===========
The valuation allowance for deferred tax assets as of January 1, 2000 and
1999 was $4,842,000 and $4,173,000, respectively. The net change in the
total valuation allowance for the years ended December 31, 2000 and 1999
was an increase of $669,000 and a decrease of $714,000, respectively. In
assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred
tax assets will not be realized. The ultimate realization of deferred tax
assets is dependent upon the generation of future taxable income during the
periods in which those temporary differences become deductible. The net
deferred tax asset at December 31, 2000 and 1999 has been offset entirely
by a valuation allowance due to the uncertainty of the ultimate realization
of such benefits.
As of December 31, 2000, the Company has an estimated net operating loss
carryforward for U.S. federal income tax purposes of approximately
$11,500,000 which is available to offset future taxable income, if any.
These net operating loss carryforwards expire in various years, beginning
in 2013, through 2020.
F-14
46
(8) SHAREHOLDERS' EQUITY
The following table lists warrants outstanding at December 31, 2000 and
1999.
Warrants Outstanding
---------------------------------------------------------------
Exercise Number of
Expiration Date Price Warrants
--------------------------------- -------- ----------
June 1, 2005 $ 1.50 50,000
January 20, 2001 $ 2.00 500,000
January 20, 2001 $ 3.00 544,706
----------
1,094,706
==========
(9) RELATED PARTY TRANSACTIONS
Certain officers and shareholders of the Company have working interests in
certain properties operated by the Company. In addition, they participate
with the Company in developing certain properties.
The Company receives $2,500 per month from Venus Oil Company, which is
owned by certain shareholders of the Company, for overhead reimbursement of
certain administrative costs. At December 31, 2000, Venus Oil Company owed
the Company $57,152 while at December 31, 1999, the Company owed Venus Oil
Company $39,387. The amount due from Venus Oil Company at December 31,
2000, was paid during March, 2001.
(10) STOCK OPTIONS
The Company has adopted an incentive plan that authorizes the grant of
awards to employees, consultants, contractors and non-employee directors.
The awards to employees, consultants and contractors can be in the form of
options, stock appreciation rights, stock or cash. The awards to
non-employee directors are limited to grants for shares of the Company's
common stock. The Company issued 79,873 shares of the Company's common
stock in 2000 to non-employee directors. The plan is administered by the
compensation committee of the Company's board of directors.
In 1998, the Company issued 100,000 shares of restricted stock to two
employees for services provided. The stock vests over three years. The
Company recorded the transaction at fair market value of the stock on the
date of the transaction, $337,500, and is amortizing the cost straight-line
over the vesting period.
At the annual shareholders meeting December 12, 2000 the Company's
incentive plan was amended to set the number of shares of the Company's
stock that is subject to the incentive plan at 2,000,000, less the number
of shares that were subject to previous plans of the Company and that are
not assumed by the current incentive plan. As of December 31, 2000, the
Company had reserved 1,417,136 shares out of the 2,000,000 shares available
for the incentive plan.
F-15
47
In 2000 the Company granted 366,244 options at fair market value and there
were 17,873 options expired or surrendered. 349,402 of the options granted
in 2000 were issued under a salary reduction plan and vested by December
31, 2000. In addition to the options granted in 2000 for salary reduction,
16,842 were granted for employment and consulting incentive. They will vest
April 30, 2001.
YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------------
2000 1999 1998
--------------------------- -------------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Options Price Options Price Options Price
----------- ----------- ----------- ----------- ------------ ---------
Options outstanding, 741,846 2.045 519,000 $ 2.534 390,000 $ 1.782
beginning of period
Expired -- -- (20,000) $ 3.290 -- --
Surrendered (17,873) 3.269 (14,611) $ 2.639 (79,000) $ 1.500
Granted 366,244 1.108 257,457 $ 1.155 218,000 $ 3.486
Exercised -- -- -- -- (10,000) $ 2.125
----------- ----------- ------------
Options outstanding,
end of period 1,090,217 1.632 741,846 $ 2.045 519,000 $ 2.534
=========== =========== ============
Options exercisable,
end of period 1,036,710 1.575 638,846 $ 1.693 344,500 $ 1.756
=========== =========== ============
The following summarizes information about stock options outstanding at
December 31, 2000:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------------------------------------- ---------------------------------
Weighted-
Average
Remaining Weighted- Weighted-
Range of Options Contractual Average Options Average
Exercise Outstanding Life Exercise Outstanding Exercise
Prices at Year End (Years) Price at Year End Price
---------------------- -------------- ------------- ------------ -------------- ---------------
$0.66 - $0.99 51,759 7.66 $ 0.780 51,759 $ 0.780
$1.00 - $1.49 667,291 5.97 $ 1.120 650,449 $ 1.180
$1.50 - $1.99 151,500 4.82 $ 1.790 151,500 $ 1.558
$2.00 - $2.99 32,000 6.69 $ 2.080 29,000 $ 2.078
$3.00 - $3.71 187,667 4.68 $ 3.478 154,002 $ 3.425
F-16
48
The Company applies APB No. 25 in accounting for its stock option plan,
accordingly, the only compensation cost recognized for its stock options in
the financial statements is the estimated value of stock options issued to
consultants related to an arrangement whereby certain consultants reduced
their fees in exchange for the stock options and costs associated with the
conversion of some options from qualified to nonqualified. Had the Company
determined compensation cost based upon the fair value at the date of grant
for its stock options under SFAS No. 123, the Company's net income would
have been reduced to the pro forma amounts indicated below:
2000 1999
------------ -----------
Net income (loss):
As Reported $ (1,516,310) $ 1,009,584
Pro forma (1,825,946) 684,438
Earnings (loss) per share, basic and diluted:
As Reported $ (.13) $ 0.09
Pro forma (.16) 0.06
The fair value of each option grant was estimated on the date of grant
using the Black-Scholes option pricing model with the following
assumptions:
2000 1999
---- ----
Expected option life (years) 3-9 4-9
Risk-free interest rate 5.17% 4.80%
Volatility 71.05% 73.49%
Dividend yield None None
(11) EMPLOYEE BENEFIT PLAN
The Company has a Profit Sharing 401(k) Plan (the Plan). Benefits under the
Plan are based on the participants vested interests in the value of their
respective accounts at the time the benefits become payable as a result of
retirement, separation from service, or other events. Eligible participants
include all Company employees who have reached age 21 and have completed
three months of service with the Company. Employees may elect to contribute
a portion of their base compensation to the Plan. The Company may make
matching contributions on behalf of the participants based on actual
participant contributions. Employer contributions are discretionary. The
Company made contributions to the Plan of $4,585, $4,613, and $12,764 for
2000, 1999, and 1998, respectively.
(12) COMMITMENTS AND CONTINGENCIES
The Company leases office space and certain automobiles under noncancelable
operating leases. The following is a schedule of future minimum lease
payments under noncancelable operating leases with initial or remaining
lease terms in excess of one year as of December 31, 2000:
YEARS ENDING DECEMBER 31,
2001 $ 303,301
2002 287,333
2003 12,125
----------
Total future minimum lease payments $ 602,759
==========
Rental expense under operating leases was $289,486, $278,856, and $335,860
for the years ended December 31, 2000, 1999, and 1998, respectively.
Effective July 1, 1999, the Company entered into a noncancelable sublease
agreement whereby it has subleased excess office space to a third party.
The sublease expires on
F-17
49
August 26, 2001, the same date the Company's primary lease expires on the
same office space. Under the sublease agreement, for 2001 the Company
expects to receive $12,000.
(13) SUPPLEMENTAL OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
(a) Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
2000 1999 1998
---------- ---------- ----------
Property acquisition costs:
Proved $ 57,796 $ 179,107 $ 189,053
Unproved 4,922 -- 130,686
Exploration costs 726,107 584,210 1,791,454
Development costs 1,668,174 421,555 2,589,804
(b) Results of Operations for Oil and Gas Producing Properties
YEARS ENDED DECEMBER 31,
--------------------------------------------
2000 1999 1998
------------ ------------ ------------
Oil and gas revenues $ 3,718,364 $ 2,183,681 $ 2,804,749
Production expenses (1,456,334) (1,025,947) (1,609,733)
Exploration expenses, including dry holes (1,159,132) (664,581) (1,261,557)
Impairment of oil and gas properties -- (544,740) (2,803,152)
Depreciation, depletion and amortization (694,743) (663,236) (1,774,999)
------------ ------------ ------------
Operating gain (loss) 408,155 (714,823) (4,644,692)
Income tax expense -- -- --
------------ ------------ ------------
Results of operations from producing activities $ 408,155 $ (714,823) $ (4,644,692)
============ ============ ============
F-18
50
(c) Reserve Quantity Information
The following table presents the Company's estimate of its proved oil
and gas reserves, all of which are located in the United States. The
Company emphasizes that reserve estimates are inherently imprecise and
that estimates of new discoveries are more imprecise than those of
producing oil and gas properties. Accordingly, the estimates are
expected to change as future information becomes available. The
estimates have been prepared by independent petroleum reservoir
engineers, in conjunction with the Company's internal petroleum
reservoir engineers.
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------
2000 1999 1998
-------------------- -------------------- --------------------
Oil Gas Oil Gas Oil Gas
(mbbl) (mmcf) (mbbl) (mmcf) (mbbl) (mmcf)
-------- -------- -------- -------- -------- --------
PROVED RESERVES:
Beginning of the year 1,135 4,332 708 8,869 977 6,491
Revisions of previous
estimates (206) 145 291 (1,834) (154) 483
Extensions, discoveries
and additions 117 947 222 1,557 4 2,467
Property divestitures -- -- (2) (3,944) -- --
Production (94) (310) (84) (316) (119) (572)
-------- -------- -------- -------- -------- --------
End of year 952 5,114 1,135 4,332 708 8,869
======== ======== ======== ======== ======== ========
PROVED DEVELOPED RESERVES:
Beginning of the year 762 2,151 468 6,174 634 5,337
======== ======== ======== ======== ======== ========
End of year 554 2,485 762 2,151 468 6,174
======== ======== ======== ======== ======== ========
(d) Standardized Measure of Discounted Future Net Cash Flows
The Company's standardized measures of discounted future net cash flows
and changes therein as of December 31, 2000, 1999 and 1998 are provided
based on present values of future net revenues from proved oil and gas
reserves estimated by independent petroleum engineers in conjunction
with the Company's internal petroleum reservoir engineers in accordance
with guidelines established by the Securities and Exchange Commission.
These estimates were computed by applying appropriate current oil and
natural gas prices to estimated future production of proved oil and gas
reserves over the economic lives of the reserves and assuming
continuation of existing economic conditions. Year ended 2000
calculations were made utilizing prices for oil and natural gas that
existed at December 31, 2000 of $27.04 per barrel and $9.62 per Mcf,
respectively. Income taxes are computed by applying the statutory
federal income tax rate to the net cash inflows relating to proved oil
and gas reserves less the tax bases of the properties involved and
giving effect to net operating loss carryforwards, tax credits and
allowances relating to such properties. The reserve volumes provided by
the independent petroleum engineers are estimates only and should not be
construed as exact quantities. These reserves may or may not be
recovered and may increase or decrease as result of future operations of
the Company and changes in market conditions.
F-19
51
YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
--------------------------------------
2000 1999 1998
---------- ---------- ----------
Future cash flow $ 75,493 $ 38,106 $ 24,477
Future development costs (6,050) (5,065) (2,051)
Future production costs (17,504) (13,159) (7,405)
---------- ---------- ----------
Future net cash flows before income taxes 51,939 19,882 15,021
Income taxes (12,282) * *
---------- ---------- ----------
Future net cash flows after income taxes 39,657 19,882 15,021
10% annual discount (16,121) (8,462) (6,883)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows after income tax $ 23,536 $ 11,420 $ 8,138
========== ========== ==========
(*) No income tax expense has been reflected as the Company had operating
loss carryforwards from oil and gas operations and sufficient tax basis
in oil and gas properties to offset the future net cash flows before
income taxes.
(e) Principal Sources of Changes in the Standardized Measure of Discounted
Future Net Cash Flows
YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
--------------------------------------
2000 1999 1998
---------- ---------- ----------
Standardized measure of discounted future net cash $ 11,420 $ 8,138 $ 11,397
flows, beginning of year
Revisions of previous quantity estimates (3,992) (81) (2,719)
Net changes in prices and production costs and other 18,129 3,391 (4,220)
Changes in estimated future development costs (244) (90) 1,585
Development costs incurred during period that reduced
future development costs 559 113 524
Sales of reserves in place -- (2,752) --
Extensions and discoveries 6,299 3,100 1,580
Sales of oil and gas produced during the period, net
of production costs (2,488) (1,213) (1,149)
Income taxes (7,289) -- --
Accretion of discount 1,142 814 1,140
---------- ---------- ----------
Standardized measure of discounted future net cash
flows, end of year $ 23,536 $ 11,420 $ 8,138
========== ========== ==========
F-20
52
(14) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Summarized quarterly financial data for 2000 and 1999 (in thousands, except
per share data) are as follows:
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
--------- --------- --------- --------- ---------
2000
Oil and gas revenues $ 934 $ 886 $ 931 $ 967 $ 3,718
Operating profit (loss) (381) (309) (193) (603) (1,486)
Net income (loss) (5) (519) (333) (659) (1,516)
Earnings (loss) per share:
Basic -- (.05) (.03) (.05) (.13)
Diluted -- (.05) (.03) (.05) (.13)
1999
Oil and gas revenues $ 385 $ 434 $ 644 $ 721 $ 2,184
Operating profit (loss) (832) (465) (436) (1,273) (3,006)
Net income (loss) (130) (575) (795) 2,510 1,010
Earnings (loss) per share:
Basic (0.01) (0.05) (0.07) 0.23 0.09
Diluted (0.01) (0.05) (0.07) 0.21 0.09
The fourth quarter of 1999 includes adjustments to reflect the impairment
of oil and gas properties of approximately $544,740. The sum of the
quarterly earnings per share will not necessarily equal earnings per share
for the entire year.
(15) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
The Company paid $428,938, $392,295, and $464,825, for interest in 2000,
1999, and 1998 , respectively. The Company assigned overriding royalty
interests to a lender totaling $30,605 for 1998. In addition, the Company
received in 1998 overriding royalty interests valued at $96,737 and stock
warrants valued at $20,000. In 1998, the Company issued 1,100,000 shares of
Common Stock in exchange for outstanding long-term debt of the Company
totaling $1,605,632. On December 31, 1999, EXUS distributed properties with
a cost basis of $13,813,161 and notes payable of $7,100,000 to the Company.
In 2000, the Company issued 1,142,854 shares of common stock in exchange
for $1,000,000 of its convertible-subordinated notes.
(16) LIQUIDITY
The Company's assets are predominately real property rights and
intellectual information that it developed regarding those properties and
other geographical areas that the Company is studying for exploration and
development. The market for these types of properties fluctuates and can be
very small. Therefore, the Company's assets can be very illiquid and not
easily converted to cash. Even if a sale can be arranged, the price may be
significantly less than what the Company believes the properties are worth.
That lack of liquidity can have materially adverse effects on the Company's
strategic plans, normal operations and credit facilities.
At December 31, 2000, the Company had a working capital deficit of
$2,835,000. Additionally, the Company's existing bank loan agreement
expires on May 8, 2001. Although it is the Company's intent to refinance
the outstanding balance, at this point the Company has not yet obtained a
commitment from a lender for such refinancing. Future availability of
credit will depend on the success of the Company's development program and
its ability to stay in compliance with credit facility debt covenants.
Management believes that the higher prices being received for oil and gas,
the recent successes in the Constitution Field in Jefferson County, Texas,
and the development wells planned to be drilled will contribute
significantly to the ability to fund operations. Management expects that it
will be able to renew or refinance the credit facility and that credit
facility will be sufficient to provide the capital to drill development
wells in the Constitution Field and four other fields. To the extent the
Company is successful in its development drilling
F-21
53
activities, the borrowing base should increase, and that should fund
additional development wells in the more promising fields.
Although management believes that the Company will be able to refinance its
credit facility at levels that are sufficient to fund the business plan for
2001, future availability of credit will depend on the success of the
development program and the Company's ability to stay in compliance with
credit facility debt covenants. In the event the current credit facility is
not renewed, management believes that it will be successful in obtaining
alternative sources of debt or equity financing. On April 1, 2001, the
Company's lender determined its borrowing base to be $1,130,000. As of
April 2, the Company had no additional availability under the credit
facility.
F-22
54
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
*3.1 Articles of Incorporation of Venus Exploration, Inc. (incorporated by
reference to Exhibit 3.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
*3.2 Bylaws of Venus Exploration, Inc., as amended (incorporated by
reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
*4.1 Warrant to purchase Common Stock issued to Martin A. Bell (incorporated
by reference to Exhibit 4.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997)
*4.2 Form of Registration Rights Agreement between Venus Exploration, Inc.
and various holders of 7% Convertible Subordinated Notes (incorporated
by reference to Exhibit 10.5 to the Company's Quarterly Report on Form
10-Q for the period ended June 30, 1999)
*+4.3 Form of Salary Reduction Stock Option Agreement (incorporated by
reference to Exhibit 4.1 to the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 1999)
*+10.1 Registrant's 1985 Incentive Stock Option Plan (incorporated by
reference to Exhibit 10.12 to the Company Registration Statement on
Form S-4 (File No. 33-1903) declared effective January 8, 1986)
*+10.2 Registrant's 1995 Incentive Stock Option Plan (incorporated by
reference to Exhibit 10.1 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1995)
+10.3 1997 Incentive Plan, as amended and restated (filed herewith)
*10.4 Letter Agreement dated February 4, 1999, between Venus Exploration,
Inc., and Petroleum Development Corporation (incorporated by reference
to Exhibit 2.1 to the Company's Current Report on Form 8-K filed
February 26, 1999)
*10.5 Amendment to Letter Agreement dated February 11, 1999, between Venus
Exploration, Inc., and Petroleum Development Corporation (incorporated
by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K
filed February 26, 1999)
*+10.6 Executive Employment Agreement dated July 1, 1999, for E.L. Ames, Jr.
(incorporated by reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30, 1999)
*10.7 Registration Rights Agreement dated November 30, 1998 between Venus
Exploration, Inc. and Stratum Group, L.P. (incorporated by reference to
Exhibit 4.4 to the Company's Registration Statement on Form S-3 (File
No. 333-73457) filed March 5, 1999)
*10.8 Purchase and Sale Agreement between Apache Corporation as seller, and
Venus Exploration, Inc., buyer, dated May 13, 1999 (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K
filed July 15, 1999)
*10.9 Credit Agreement among EXUS Energy, LLC, as borrower, NationsBank,
N.A., as administrative agent, and financial institutions listed on
Schedule I, dated June 30, 1999 (incorporated by reference to Exhibit
10.2 to the Company's Current Report on Form 8-K filed July 15, 1999)
*10.10 Limited Liability Company Agreement of EXUS Energy, LLC, dated June 30,
1999 (incorporated by reference to Exhibit 10.3 to the Company's
Current Report on Form 8-K filed July 5, 1999)
55
*10.11 Convertible Promissory Note made by Venus Exploration, Inc. in favor of
EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to
Exhibit 10.4 to the Company's Current Report on Form 8-K filed July 15,
1999)
*10.12 Pledge Agreement made by Venus Exploration, Inc. for the benefit of
EXCO Resources, Inc., dated June 30, 1999 (incorporated by reference to
Exhibit 10.5 to the Company's Current Report on Form 8-K filed July 15,
1999)
*10.13 Registration Rights Agreement between EXCO Resources, Inc. and Venus
Exploration, Inc., dated June 30, 1999 (incorporated by reference to
Exhibit 10.6 to the Company's Current Report on Form 8-K filed July 15,
1999)
*10.14 Agreement Among Members between EXCO Resources Inc., dated June 30,
1999 (incorporated by reference to Exhibit 10.7 to the Company's
Current Report on Form 8-K filed July 15, 1999)
*10.15 Purchase and Sale Agreement between Venus Exploration, Inc. as seller,
and Anadarko Petroleum Corporation, as buyer, dated December 17, 1999
(incorporated by reference to Exhibit 10.1 to the Company's Current
Report on Form 8-K filed July 18, 2000)
*10.16 Amendment to Purchase and Sale Agreement dated December 17, 1999,
between Venus Exploration, Inc. as seller, and Anadarko Petroleum
Corporation., buyer, dated December 31, 1999 (incorporated by reference
to Exhibit 10.31 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000)
+10.17 Consulting Agreement effective October 30, 2000, between Venus
Exploration, Inc. and P. Mark Stark (filed herewith)
*21.1 List of Subsidiaries (incorporated by reference to Exhibit 21 to the
Company's Annual Report on Form 10-K for the year ended December 31,
1997)
23.1 Consent of KPMG LLP regarding incorporation by reference (filed
herewith)
23.2 Consent of Ryder Scott Company regarding incorporation by reference
(filed herewith)
- ----------
* Incorporated herein by reference.
+ Management contract or compensatory plan or arrangement.