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, 2001

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the transition period from _________________ to _________________

Commission File Number 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 810, 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, 2002, was approximately $2,010,000. As of March 19, 2002, the
Registrant had outstanding 12,448,730 shares of Common Stock.

TABLE OF CONTENTS

<Table>

PART I....................................................................................................................3
ITEM 1. BUSINESS.....................................................................................................3
ITEM 2. PROPERTIES..................................................................................................14
ITEM 3. LEGAL PROCEEDINGS...........................................................................................18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........................................................18
PART II..................................................................................................................18
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS...................................18
ITEM 6. SELECTED FINANCIAL DATA.....................................................................................19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.......................20
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..................................................26
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................................................................26
ITEM 9. CHANGES IN, AND DISAGREEMENTS WITH, ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE......................26
PART III.................................................................................................................27
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................................27
ITEM 11. EXECUTIVE COMPENSATION......................................................................................29
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..............................................34
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................................36
PART IV..................................................................................................................37
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS SCHEDULES....................................................................37
</Table>

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 5.

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 12. Those terms and abbreviations are usually
capitalized in the text.

Proved Reserves as of December 31, 2001, totaled 7.6 Bcfe, a decrease of 3.4
Bcfe from the 11.0 Bcfe that we reported at year-end 2000, a 30.90% decrease.
The decrease is due to the downward revision of reserves of some existing
properties, caused by lower unit prices at December 31, 2001 as compared to
December 31, 2000, and by normal production. Production for 2001 totaled .9
Bcfe. Production was partially offset by .02 Bcfe of net new reserves added
through discoveries and extensions, but revisions of previously estimated
reserves showed a decrease of 2.4 Bcfe. In 2001, average daily net production
decreased to 2,340 Mcfe/day from 2,400 Mcfe/day in 2000, a 2.5% decrease. The
decrease is due to normal fluctuations. As of December 31, 2001, approximately
46% of our reserves are natural gas reserves. As of December 31, 2000,
approximately 35% of our reserves were natural gas. Venus operates 39% 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

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.

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 OTC Bulletin Board under
the symbol VENX.OB. 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, 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

Set forth below is an update of significant developments during 2001 and 2002

Financial Advisor - In light of our working capital position, in March
2002, we engaged a financial advisor to assist us in exploring all financial
alternatives ranging from recapitalization of the Company to a merger or sale of
the Company or certain of its properties.

Secured Note to Replace Certain Trade Debt - We are negotiating with
one of our largest trade creditors to enter into a promissory note that would
replace our current trade indebtedness to that creditor. This note would be
secured by a second lien on the assets presently pledged to our primary lender.
The trade creditor also requires the personal guaranty of this note by E.L.
Ames, Jr., our Chairman and CEO. Pursuant to the terms of our credit agreement,
we must obtain the consent of our primary lender before completing this
transaction.

Nasdaq Listing - On May 29, 2001, Nasdaq sent us a letter stating that
we were not in compliance with The Nasdaq SmallCap Market listing requirements
because our net tangible assets were below the $2 million minimum. We also did
not comply with Nasdaq's newly proposed continued listing standard of $2.5
million in stockholders' equity. On June 13, 2001, we submitted to Nasdaq our
specific plan to achieve and sustain compliance with The Nasdaq SmallCap Market
listing requirements. On August 8, 2001, Nasdaq sent us a letter stating that
Nasdaq was denying our request for continued listing submitted in June. We
requested and received a hearing to appeal Nasdaq's determination, which hearing
was held on October 18, 2001. Pending the decision, the Company's securities
remained listed on The Nasdaq SmallCap Market. On January 8, 2002, we received
notice from Nasdaq, that our stock was no longer eligible to be traded on the
Nasdaq SmallCap Market and that our stock would begin trading on the OTC
Bulletin Board. Our stock began trading on the OTC Bulletin Board on January 9,
2002.

Current Credit Facility - On July 6, 2001 (the "Loan Closing Date"), we
entered into a new Loan Agreement with a bank that was initially for a two year,
$5,000,000 revolving line of credit. The line of credit is subject to a
borrowing base based on oil and gas reserves to be redetermined by the bank at
any time but must be evaluated every six months. We may request a
redetermination one time per year. The initial borrowing base under this Loan
Agreement was $2,000,000, with reductions of $50,000 per month during the term
of the facility. The $1,130,000 outstanding under the our old line of credit was
repaid through advances under this new line of credit with the bank. We are
using the remaining facility for acquisition and development of oil and gas
properties and for general working capital purposes, including letters of
credit. The facility initially bore interest at either the Wall Street Journal
Prime Rate plus the applicable Prime Rate Margin (250 basis points if more than
two-thirds (2/3) of the commitment was outstanding, and zero basis points if
less) or the Eurodollar Rate (LIBOR) plus the applicable LIBOR Margin, at the
option of the Company. Eurodollar Rate credit facility pricing varied from LIBOR
+ 225 basis points if less than one-third of the commitment was outstanding, to
LIBOR + 250 basis points for one-third to two-thirds of the commitment, to LIBOR
+ 275 basis points if greater than two-thirds of the commitment was outstanding.
As of December 11, 2001, we entered into an amendment of our current credit
facility whereby the interest rate was increased to the Wall Street Journal
Prime Rate plus 200 basis points, and the revolving line of credit and the
borrowing base were each reduced to $1,900,000. In conjunction with a sale of
oil and gas properties that occurred on January 31, 2002, we entered into
another amendment to the current credit facility where the term of the loan
agreement was changed from July 5, 2003 to June 30, 2002, and the revolving line
of credit and the borrowing base were each reduced to $1,850,000. As of March
21, 2002, we entered into an amendment of our current credit facility whereby
the revolving line of credit was reduced to $938,454 and the borrowing base was
reduced to $938,454, with reductions to such borrowing base of $50,000 per month
during the term of the facility, and an additional reduction of $100,000 to
occur on April 2, 2002, upon the expiration of a letter of credit.

Successful Completions in the Constitution Field - During 2000, we
successfully drilled two development wells in Jefferson County, Texas, in the
Constitution Field. On February 26, 2001, we commenced drilling the fourth well
in this field, the Kolander #1, which was completed on May 19, 2001. The initial
production rate was 2.900 million cubic feet of gas per day (MMCF) and 525
barrels of condensate per day flowing through 16/64 inch choke with 3,367 psi
flowing tubing pressure. On July 18, 2001, we commenced drilling the fifth well
in this field, the Maness #1. The well is still being evaluated for a sidetrack
operation.

RISK FACTORS

Working Capital Deficit - We incurred a significant working capital
deficit during 2001 in the course of drilling exploration and development wells
and acquiring acreage for drilling prospects. In connection with those
activities we have significantly increased our trade payables, both in dollar
amount and the period for which they are delinquent. While our relationship with
our creditors has remained positive and they have continued to work with us
during this period of limited working capital, there is no assurance that such
support will continue. Even though we do not anticipate continuing our drilling
activities until we have obtained some working capital relief, there is no
assurance that our creditors will not take actions in the meantime that could be
detrimental to our efforts in that regard. In order to resolve our working
capital deficit, we have engaged a financial advisor us to assist us in
exploring all financial alternatives ranging from a recapitalization of the
Company to a merger or sale of the Company or certain of its properties. There
can be no assurances, however, that these events will occur, and their timing
may be uncertain.

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, in 2000 the operating loss was $1.5 million, and in 2001
the operating loss was $3.1 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, 2001, we had an accumulated deficit of approximately
$19.8 million.

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 2001 we received a series of waivers from our previous lenders for
defaults of certain financial covenants in our revolving credit agreements. We
entered into our current credit facility in July 2001. It has similar financial
covenants that we failed to satisfy as of December 31, 2001, 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 Exploration and 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 seek compliance with our current financial covenants, there is no assurance
that management can do so.

Substantial Capital Requirements - We rely on bank and other financing
to implement our business plan. Our credit facility expires on June 30, 2002.
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. There can be no assurance that our line of credit will be renewed
with either our present lender or an alternative financial institution.

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 a materially adverse effect on our strategic plans, normal operations and
credit facilities.

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.

Likewise the price spike for natural gas that occurred in late 2000 and early
2001 did not last long enough for us to take full advantage of the higher
prices. In fact, the subsequent price drop later in 2001 only highlighted the
volatility and lack of predictability of gas prices.

On a pro forma basis for the twelve months ended December 31, 2001, excluding
the oil and gas sales from non-core properties sold in 2002, our 2001 production
was 62% 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 in early 2002, 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, 2001. Also on a pro forma basis, a $1.00
per Bbl change in average oil prices would have resulted in approximately an
$85,000 difference in gross revenue for the twelve months ended December 31,
2001.

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 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.

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 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.

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,

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.

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, 2001, there were 1,140,217
shares of our common stock currently issueable 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, 2001, Range
Resources Corporation and our current officers and directors as a group
beneficially own more than forty-two percent (42%) 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 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
Dr. Ewing and Ms. Weise, both 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. Mr. Ames, Jr.'s
employment agreement expired on July 1, 2001 and Mr. Ames, Jr. continues to be
paid on a month to month basis under the same terms as were in place under the
agreement, one of which was a non-compete provision.

Existence as an OTC Bulletin Board Company - On January 8, 2002, we
received notice from Nasdaq, that our stock was no longer eligible to be traded
on the Nasdaq SmallCap Market and that our stock would begin trading on the OTC
Bulletin Board. Our stock began trading on the OTC Bulletin Board on January 9,
2002. 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 our
common stock.

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 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. Hedging instruments are generally collars but may include
fixed price swaps and, put and call options on futures. While hedging limits our
exposure to adverse price movements, hedging limits the benefit of price
increases and is subject to a number of risks, including the risk the
counterparty to the hedge may not perform.

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, health and
safety 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 the potentially applicable federal laws 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.

In addition, the states in which we operate have comparable state statutes and
regulations which may be more stringent than their federal counterparts. 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 and may require us to incur significant capital
expenditures to meet regulatory pollution control or emission standards.

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 potentially 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, currently managed as
non-hazardous waste, including wastes generated during drilling and production
operations, as "hazardous wastes" under RCRA. Hazardous wastes are subject to
more rigorous and costly disposal and management requirements than are
non-hazardous wastes. Such changes in the regulations may result in additional
capital expenditures or operating expenses by the Company. While state laws vary
on this issue, state initiatives to further regulate oil and gas wastes could
have a similar impact.

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 2001. Those are Duke Energy Field Services, Inc. (19%), Flying J Oil
& Gas, Inc. (17%), and Gulfmark Energy, Inc. (14%). In 2000, three customers
each accounted for approximately 10% or more of consolidated revenues. Those
were Flying J Oil & Gas, Inc. (26%), Duke Energy Field Services, Inc. (13%), and
Gulfmark Energy, Inc. (10%).

EMPLOYEES

As of March 15, 2002, the Company had 12 employees.

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.

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.

ITEM 2. PROPERTIES

OIL AND NATURAL GAS RESERVES

As of December 31, 2001, 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, 2001, 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) and U.S Department of Energy Form EIA-23. The following table
summarizes our estimates of our net Proved Reserves and their PV-10 Value as of
December 31, 2001.

PROVED RESERVES
(AS OF DECEMBER 31, 2001)
----------------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
------------ ------------ ------------

Oil and Condensate (Mbbls) 424.84 234.17 659.01
Natural Gas (Bcf) 2.08 1.56 3.64
Combined Equivalent BCF (Bcfe) 4.63 2.97 7.60
PV-10 Value (in thousands)(1) 4,505.08 591.14 5,096.22
============ ============ ============
</Table>

PROVED RESERVES BY STATE
(AS OF DECEMBER 31, 2001)
- ---------------------------------------------------------------------------------------------------------------
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 81 262 3.17 4.74 62.4% 3,884 76.2%
Utah 8 279 .10 1.77 23.3% 598 11.7%
Oklahoma 147 105 .37 1.00 13.2% 564 11.1%
Other (2) 7 13 -- .09 1.1% 50 1.0%
----- ------------ ------------ ------------ ------------ ------------ ------------
TOTAL 243 659 3.64 7.60 100.0% 5,096 100.0%
===== ============ ============ ============ ============ ============ ============
</Table>

(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 a decrease in value and a decrease in volume of
Proved Reserves as compared with December 31, 2000. The decreased reserves and
value are primarily due to the higher oil and natural gas prices at year-end
2000 as compared to year-end 2001, although some decrease of reserves is due to
normal production. See Note 11 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.

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
- ---------------- ----------- ----------- ----------- ----------- ----------- -----------

1999 3.00 1.00 4.00 .11 .07 .18

2000 2.00 -- 2.00 .17 -- .17

2001 3.00 1.00 4.00 .23 .19 .42
----------- ----------- ----------- ----------- ----------- -----------
Totals 8.00 2.00 10.00 .51 .26 .77
=========== =========== =========== =========== =========== ===========
</Table>

EXPLORATORY WELLS
- ----------------------------------------------------------------------------------------------------
GROSS WELLS NET WELLS
--------------------------------------- ---------------------------------------
YEAR PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
- ---------------- ----------- ----------- ----------- ----------- ----------- -----------

1999 1.00 -- 1.00 .07 -- .07

2000 -- 1.00 1.00 -- .10 .10

2001 .00 .00 .00 .00 .00 .00
----------- ----------- ----------- ----------- ----------- -----------
Totals 1.00 1.00 2.00 .07 .10 .17
=========== =========== =========== =========== =========== ===========
</Table>

PRODUCTIVE WELLS
AS OF DECEMBER 31, 2001
- ----------------------------------------------------------------------------------------------------
GROSS WELLS NET WELLS
--------------------------------------- ---------------------------------------
STATE OIL GAS TOTAL OIL GAS TOTAL
- ---------------- ----------- ----------- ----------- ----------- ----------- -----------

Texas 46 35 81 1.74 3.64 5.38

Oklahoma 128 19 147 7.72 .62 8.34

Utah 8 0 8 1.78 .00 1.78

Other(1) 5 2 7 .83 .25 1.08
----------- ----------- ----------- ----------- ----------- -----------
Totals 187 56 243 12.07 4.51 16.58
=========== =========== =========== =========== =========== ===========
</Table>

(1) Other states are Alabama, Louisiana and California.

ACREAGE

The following table sets forth our Developed and Undeveloped Acreage as of
December 31, 2001:

DEVELOPED AND UNDEVELOPED ACREAGE
- --------------------------------------------------------------------------------
GROSS ACRES NET ACRES
--------------------------- ---------------------------
STATE DEVELOPED UNDEVELOPED DEVELOPED UNDEVELOPED
- -------------------- ------------ ------------ ------------ ------------

Oklahoma 17,714 -- 783 --
Texas 28,734 16,413 1,941 8,808
Utah 4,943 -- 1,504 --
Louisiana -- 3,268 -- 817
Alabama 480 -- 144 --
California 400 -- 33 --
Michigan 160 -- 8 --
Kansas -- 480 -- 480
------------ ------------ ------------ ------------
Totals 52,431 20,161 4,413 10,105
============ ============ ============ ============
</Table>

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
- ------------- ------------ ------------ ------------ ------------ --------------

1999 84 .316 17.54 2.23 1.25
2000 94 .310 28.17 4.12 1.66
2001 88 .326 24.49 4.54 1.74
</Table>

*Includes severance taxes and ad valorem taxes.

NOTE: ALL OF OUR PRODUCTION IS IN THE UNITED STATES.

After December 31, 2001, we sold properties in Jasper County, Texas. Production
for 2001 attributable to the properties sold totaled 3,345 barrels of oil and
19,872 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 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 - Of the properties we own and operate, we hold approximately
4,377 gross (4,020 net) acres and own a 15% working interest in the
Constitution Field in Jefferson County, Texas. We underwrote a 3D seismic
survey shot over the Constitution Field in 1999. Our technical staff interpreted
this data and integrated the information with other subsurface geological
information. We estimate that 5 proved, undeveloped drill sites with a total of
9 zones remain in the Constitution Field. The independent engineering consulting
firm of Ryder Scott Company concurs with four of these drill sites. We have
completed four wells in the field. On February 26, 2001, we commenced drilling
the Kolander # 1, the fourth well in this field, and it was completed on May 19,
2001. The initial production rate was 2.90 million cubic feet of gas per day
(mmcf) and 525 barrels of condensate per day flowing through a 16/64 inch choke
with 3,367 psi flowing tube pressure. On July 18, 2001, we commenced drilling
the fifth well in this field, the Maness # 1. We are now evaluating the well for
sidetrack operation.

Sale of Properties - On January 31, 2002, we closed on the sale of properties in
Jasper County, Texas for an aggregate gross price of approximately $900,000.

OFFICE LEASE

In May 1997, we relocated our executive and operating offices to San Antonio,
Texas, where we occupy premises of approximately 8,408 useable square feet
pursuant to a lease that expires on May 31, 2006. The lease of the San Antonio
office space provides for increased expenses at stated amounts and intervals and
an adjustment for variations in utility costs. In addition, we have a lease of
12,570 useable square feet of space which terminates December 31, 2002.
Effective July 1, 2001 we entered into a noncancelable sublease agreement
whereby we subleased excess office space to a third party. The sublease expires
on December 31, 2002, the same date our primary lease expires on the same office
space. Under the sublease agreement, for 2002, we expect to receive $245,735.

We also had an office in Houston, Texas. The Houston office address was 363 W.
Sam Houston Parkway, Suite 490, Houston, Texas 77060. That lease terminated on
August 26, 2001 and we no longer have any operations or personnel in Houston.
Our annual rental expense was approximately $203,000 during 2001.

See "Item 1 - BUSINESS" for additional information concerning our oil and gas
properties.

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, 2001, 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

None.

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS

On January 9, 2002, our common stock began trading on the OTC Bulletin Board
under the symbol, VENX.OB and is currently trading on the OTC Bulletin Board.
Prior to January 9, 2002, our Common Stock traded on the NASDAQ SmallCap
Market(SM) 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
------------ ------------

2001
First Quarter $ 1.3125 $ .7500
Second Quarter 1.8300 .3100
Third Quarter 1.2500 .6100
Fourth Quarter .9500 .4500

2000
First Quarter $ 2.0000 $ .4375
Second Quarter 1.0625 .6562
Third Quarter 1.1875 .6250
Fourth Quarter 1.8750 .7500
</Table>

On March 19, 2002, the closing bid price, on the OTC Bulletin Board, for our
Common Stock was $.40 per share.

We had 958 stockholders of record as of February 26, 2002, (including 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, 2001, there were 1,140,217 shares of our
common stock currently issuable upon exercise of outstanding warrants or vested
options. The exercise prices and expiration dates for all these outstanding
warrants and options are as follows:

<Table>
<Caption>
NUMBER OF OPTIONS OR
WARRANTS EXERCISE PRICE EXPIRATION DATE
------------------- ----------------- ---------------

179,016 $0.6562 - $1.0470 Various times in 2009 through 2010

136,801 $1.1191 March 2009

150,396 $1.1520 - 1.1875 Various times in 2005 through 2010

108,311 $1.2310 March 2004

20,000 $1.2500 August 2003

100,000 $1.3125 July 2004

24,526 $1.4900 March 2009

181,500 $1.5000 - 1.5125 Various times in 2004 through 2005

20,000 $1.8750 January 2006

32,000 $2.00 - 2.1250 various times in 2007 and 2008

187,667 $3.29 - 3.7125 various times in 2003 and 2008
- ------------------
TOTAL - 1,140,217
</Table>

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.

We entered into our current credit facility with a bank effective July 6, 2001.
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.

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, 2001, 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, 2001

<Table>
<Caption>
(IN THOUSANDS, EXCEPT PER SHARE INFORMATION)
-------------------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------

Total revenues $ 3,302 $ 3,718 $ 2,184 $ 2,805 $ 2,476
Income (loss) before extraordinary items (3,051) (1,266) 1,010 (8,324) (4,168)
Net income (loss) (3,051) (1,516) 1,010 (8,670) (4,168)
Per common share:
Net income (loss) -- Basic (.25) (.13) 0.09 (0.87) (0.57)
Net income (loss) -- Diluted (.25) (.13) 0.09 (0.87) (0.57)
Long term debt -- -- 1,750 -- 2,005
Other long-term liabilities 28 13 18 23 27
Total assets 9,392 7,117 24,465 8,136 12,931
</Table>

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 OTC Bulletin Board
under the symbol VENX.OB. 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 eight states, including Texas, Louisiana,
Oklahoma and Utah. Our current geological and geographical areas of focus 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

During 2001, we participated in drilling 5 wells. One of the five wells was
exploratory, and the other four 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 was a reentry, and the other was a sidetrack to develop reserves in the
Yegua Formation in Wharton County, Texas. Two other development wells were
drilled in another Yegua Formation gas field in Jefferson County, Texas.

Because of the improving natural gas prices in 2000 and increased demand for
natural gas, and increased cash flows within the industry, we increased
generation of exploratory prospects in 2001. This prospect generation activity
was and will 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, 2001, totaled 7.6 Bcfe, a decrease of 3.4
Bcfe from the 11.0 Bcfe we reported at year-end 2000, a 30.9% decrease.
Production for 2001 totaled .9 Bcfe. Production was partially offset by .02 Bcfe
of net new reserves added through discoveries, extensions, but revisions of
previous estimated reserves showed a decrease of 2.4 Bcfe. In 2001, average
daily net production decreased to 2,340 Mcfe/day from 2,400 Mcfe/day in 2000, a
2.5% decrease. The production decrease was due to normal fluctuations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operation
are based upon consolidated financial statements, which have been prepared in
accordance with accounting principles generally adopted in the United States.
The preparation of these financial statements requires that we make estimates
and judgments that affect the reported amounts of assets, liabilities, revenues
and expenses. We analyze these estimates, including those related to oil and gas
revenues, bad debts, oil and gas properties, derivative instruments, income
taxes and contingencies. We base these estimates on historical experience and
various other assumptions that we believe to be reasonable under the
circumstances. Actual results may differ from these estimates under different
assumptions or conditions. We believe the following critical accounting policies
affect our more significant judgments and estimates used in the preparation of
our consolidated financial statements. We recognize revenues from the sale of
products and services in the period delivered. We provide an allowance for
doubtful accounts for specific receivables we judge unlikely to be collected.
Oil and gas properties are accounted for under the successful efforts method of
accounting and are periodically evaluated for possible impairment. Impairments
are recorded when management believes that a property's net book value is not
recoverable based on current estimates of expected future cash flows. Our
reserve estimates are prepared by engineers knowledgeable of and following the
guidelines for reserves as established by the SEC. The estimation of reserves
requires the engineers to make a significant number of assumptions based on
professional judgment. Estimated reserves are therefore, often subject to future
revision, certain of which could be substantial, based on the availability of
additional information, including: reservoir performance, new geological and
geophysical data, additional drilling, technological advancements, price changes
and other economic factors. Changes in oil and natural gas prices can lead to a
decision to start-up or shut-in production, which can lead to revisions to
reserve quantities. Reserve revisions inherently lead to adjustments of
depletion rates utilized by the Company. We can not predict the types of reserve
revisions that will be required in future periods. To the extent that we have
investments in derivative instruments, we have analyzed our accounting treatment
of them on a case by case basis and have typically not elected to treat those
investments as hedges under FAS 133.

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2001, COMPARED WITH YEAR ENDED DECEMBER 31, 2000

We reported a net loss of $3.1 million for 2001 versus a net loss of $1.5
million for 2000. Our oil and gas production was 854 Mmcfe in 2001, compared to
878 Mmcfe in 2000, a decrease of 2%. Average oil prices decreased from $28.17
per barrel in 2000 to $24.49 in 2001, a 13% decrease. Average natural gas prices
increased from $4.12 per Mcf to $4.54, an 10% increase. As a result of the
decrease in production and oil prices, oil and gas revenue decreased by $.4
million, or 11%, to $3.3 million in 2001 from $3.7 million in 2000.

Trade accounts payable at December 31, 2001 were $8,037,712 compared with
$3,435,011 on December 31, 2000, an increase of $4,602,701. This increase is
primarily attributable to the costs we incurred in connection with the drilling
of two wells in 2001, one in Wharton County, Texas and the other in Jefferson
County, Texas.

Oil and gas production costs in 2001 were $1,487,701 ($1.74 per Mcfe) compared
with $1,456,335 in 2000 ($1.66 per Mcfe). The increase in total production
expense of $.08 per Mcfe is mostly due to an increase in workover expense of
$.13 per Mcfe, a decrease in production taxes of $.14 per Mcfe and an increase
of lease operating expense (" LOE") of $.09 per Mcfe.

2001 production or lifting cost as a percentage of oil and gas sales increased
to 45%, compared with 39% in 2000. This increase is almost entirely due to
higher cost per Mcfe between the two periods as mentioned in the immediately
preceding paragraph.

During 2001, we recorded impairment expense of $276,000 as compared to none
recorded in 2000. We review for impairment whenever circumstances indicate that
the carrying value of an asset may not be recoverable. Such reviews were done
for both 2001 and 2000. 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 $1,338,385 in 2001 increased
by $179,253 from $1,159,132 in 2000. The geological and geophysical expenses
decreased by $340,000 during 2001, but dry hole and abandonment expense
increased by $519,000, mainly because of the abandonment of a well in Wharton
County, Texas.

Depreciation, depletion, and amortization (DDA) expense of $1,019,863 ($1.19 per
Mmcfe) in 2001 increased by $325,120 from $694,743 ($.79 per Mcfe) in 2000. DD&A
decreased by $19,000 because of a decrease in production, but increased $344,000
because of increased DDA rates. The rates increased because of a fall in
reserves. This fall was mostly caused by unusually high gas prices at December
31, 2000 as compared to December 31, 2001.

During 2001, general and administrative expense of $2,184,506 increased $290,302
from $1,894,204 in 2000. This increase was primarily due to increased payroll
costs and bad debt reserve during 2001.

Interest expense was $225,444 in 2001, compared to $169,217 in 2000. Interest
expense includes amortization of deferred financing cost of $110,360 in 2001 and
$72,367 in 2000. The average daily balances of interest-bearing debt was $1.3
million in 2001, compared to $1.5 million in 2000.

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 future price assumption
is based on 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.

LIQUIDITY AND CAPITAL RESOURCES

At December 31, 2001, we had a working capital deficit of $7,850,733 compared
with working capital deficit of $2,835,202 at December 31, 2000, a decrease in
working capital of $5,015,531. Working capital at year-end 2001 and year-end
2000 reflects classifying notes payable of $1,254,351 and $1,130,000,
respectively, as current.

In light of our current working capital situation, we are discontinuing our
drilling and exploration activities, and do not anticipate making any further
capital expenditures, until such time as we have significantly reduced our
deficit.

Our outstanding bank debt is due June 30, 2002. While we are in discussions with
our lender, there is no assurance that our line of credit will be renewed with
either our present lender or an alternative financial institution. Regardless of
whether a refinancing can be arranged, such refinancing is unlikely to be
sufficient to allow us to execute our business plan. Accordingly, to continue
operations, such as drilling additional development and exploration wells, as
well as acquiring additional acreage, we will have to raise capital and/or
liquidate assets. We have engaged a financial advisor to assist us in exploring
all financial alternatives ranging from a recapitalization of the Company to a
merger or sale of the Company or certain of its properties. There can be no
assurances, however, that these events will occur and their timing may be
uncertain.

Notwithstanding the foregoing we are continually seeking methods and
alternatives of financing in order to provide us with the capital to refinance
our working capital deficit and to improve our financial position. In addition,
we are reviewing our asset base so as to monetize assets that are
underperforming. Further, a portion of our business entails selling working
interest participations in oil and gas projects in order to finance certain
exploration drilling activities.

We are negotiating with one of our largest trade creditors to enter into a
promissory note that would replace our current trade indebtedness to that
creditor. This note would be secured by a second lien on the assets presently
pledged to our primary lender. The trade creditor also requires the personal
guaranty of this note by E.L. Ames, Jr., our Chairman and CEO. Pursuant to the
terms of our credit agreement, we must obtain the consent of our primary lender
before completing this transaction.

CURRENT CREDIT FACILITY

On July 6, 2001 (the "Loan Closing Date"), we entered into a new Loan
Agreement with a bank that was initially for a two year, $5,000,000 revolving
line of credit. The line of credit is subject to a borrowing base based on oil
and gas reserves to be redetermined by the bank at any time but must be
evaluated every six months. We may request a redetermination one time per year.
The initial borrowing base under this Loan Agreement was $2,000,000, with
reductions of $50,000 per month during the term of the facility. The $1,130,000
outstanding under the our old line of credit was repaid through advances under
this new line of credit with the bank. We are using the remaining facility for
acquisition and development of oil and gas properties and for general working
capital purposes, including letters of credit. The facility initially bore
interest at either the Wall Street Journal Prime Rate plus the applicable Prime
Rate Margin (250 basis points if more than two-thirds (2/3) of the commitment
was outstanding, and zero basis points if less) or the Eurodollar Rate (LIBOR)
plus the applicable LIBOR Margin, at the option of the Company. Eurodollar Rate
credit facility pricing varied from LIBOR + 225 basis points if less than
one-third of the commitment was outstanding, to LIBOR + 250 basis points for
one-third to two-thirds of the commitment, to LIBOR + 275 basis points if
greater than two-thirds of the commitment was outstanding. As of December 11,
2001, we entered into an amendment of our current credit facility whereby the
interest rate was increased to the Wall Street Journal Prime Rate plus 200 basis
points, and the revolving line of credit and the borrowing base were each
reduced to $1,900,000. In conjunction with a sale of oil and gas properties that
occurred on January 31, 2002, we entered into another amendment to the current
credit facility where the term of the loan agreement was changed from July 5,
2003 to June 30, 2002, and the revolving line of credit and the borrowing base
were each reduced to $1,850,000. As of March 18, 2002, we entered into an
amendment of our current credit facility whereby the revolving line of credit
was reduced to $938,454 and the borrowing base was reduced to $938,454, with
reductions to such borrowing base of $50,000 per month during the term of the
facility, and an additional reduction of $100,000 to occur on April 2, 2002,
upon the expiration of a letter of credit.

The facility is secured by all of our oil and gas properties, and contains the
following financial covenants:

(1) Minimum Current Ratio. Commencing on the ninety-first day after the
Loan Closing Date, the Company shall maintain, on a quarterly basis as
of the last day of each fiscal quarter, a ratio of current assets to
current liabilities of 1.0 to 1.0. For purposes of this ratio, current
assets include the unused and available portion of the Line of Credit.

requirement that shall be re-set annually after the end of each year.
For purposes of this covenant, such number shall be adjusted to
exclude non-cash items, including unrealized gains and losses, arising
from the effects, if any, of the mark to market of those Hedging
Obligations which are classified as cash flow hedges and determined
"effective" pursuant to FASB Rule 133, or of other rules pertaining to
other comprehensive income.

(3) Minimum EBITDAX to Interest. The Company shall maintain, on a
quarterly basis as of the last day of each fiscal quarter, a ratio (on
a rolling four quarter basis) of EBITDAX to interest expense of not
less than 2.00 to 1.00 through December 31, 2001, and of not less than
2.50 to 1.00 thereafter. "EBITDAX" is defined as EBITDA, but adjusted
as if the Company were to use the full cost method of accounting
(under which all exploration expenses are capitalized) to capitalize
exploration and dry hole costs rather than the Company's successful
efforts accounting method of expensing intangible drilling costs (such
as seismic and geological expenses), dry hole costs and other costs.

The facility contains other usual and standard covenants such as: debt and lien
restrictions; dividend and distribution prohibitions; restriction on changes in
key management and financial statement reporting requirements. The credit
facility also requires that we hedge at least 25% of its daily oil and gas
production for twelve months.

As of December 31, 2001, we were not in compliance with certain of our loan
covenants; however, we sought and received waivers for its non-compliance with
those loan covenants. In order for us to achieve compliance with our loan
covenants in the future, we need to raise additional capital and/or obtain
amendment of certain loan covenants.

CONTRACTUAL OBLIGATIONS

The following table provides a summary of the Company's contractual obligations
as of December 31, 2001. Additional detail about these items are included in the
notes to the consolidated financial statements.

<Table>
<Caption>
Year 2006
Contractual Obligation Year 2002 Year 2003 Year 2004 Year 2005 And After Total
- ---------------------- ---------- ---------- ---------- ---------- ---------- ----------

Indebtedness $1,254,351 -- -- -- -- $1,254,351
Operating leases 492,636 220,190 208,978 198,385 77,459 1,197,648
Other long term liabilities 25,056 20,628 7,380 -- -- 53,064
---------- ---------- ---------- ---------- ---------- ----------
Total contractual
cash obligations $1,772,043 $ 240,818 $ 216,358 $ 198,385 $ 77,459 $2,505,063
</Table>

HEDGING ACTIVITIES

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
adopted SFAS No. 133 effective January 1, 2001. Under the transition provisions
of SFAS No. 133, on January 1, 2001 we recorded 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 elected not to use
hedge accounting for derivatives existing at January 1, 2001. Subsequent changes
in fair value of those derivatives were recorded in income.

Our current credit facility requires us to hedge approximately twenty five
percent (25%) of our daily oil and gas production for a period of one year. On
September 28, 2001, we entered into commodity collar agreements for 112 barrels
of oil per day for the six month period from November 1, 2001 though April 30,
2002. The oil hedge is a costless collar with a floor of $22.20 per barrel and a
ceiling of $24.50 per barrel. If the average NYMEX price is less than $22.20 for
any month, we receive the difference between $22.20 and the average NYMEX price
for that particular month. If the average NYMEX price is greater than $24.50 for
any month, we pay the difference between $24.50 and the average NYMEX price for
that particular month. 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 December 31, 2001. Future changes in the fair
value of those derivatives will be recorded in income. We entered into this
costless collar with Enron North America Corp ("Enron"). Since we have a
receivable from Enron in the amount of $18,209, we have elected to

record a provision for bad debt in the same amount. In order to enter into this
costless collar we had to give Enron a letter of credit ("L/C") in the amount of
$100,000 with them as the benefitiory of the L/C. The L/C expires on April 1,
2002 and we and our current lender do not intend to renew the L/C.

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. Our current credit facility requires us to
hedge approximately twenty five percent (25%) of our daily oil and gas
production for a period of one year. On September 28, 2001, we entered into
commodity collar agreements for 112 barrels of oil per day for the six month
period from November 1, 2001 though April 30, 2002. 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 $24.50 per barrel ceiling, the Company's net income
would decrease by approximately $3,360 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 gain of approximately $48,000,
however, since the contract is with Enron, we have elected not to record any
gain due to the doubtful nature of the contract. We have determined that hedge
accounting will not be elected for our derivative positions existing at December
31, 2001.

While we are required to enter into hedges 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 2001, a 10% reduction in
oil and gas prices would have reduced revenue by approximately $364,000, but the
hedging activities would have decreased the reduction to approximately $293,000.

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.

Our earnings are also affected by changes in interest rates because our bank
debt ($1,254,351 at December 31, 2001) is subject to a floating prime rate plus
2%. 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,
2002; 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. 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.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The officers and directors are listed below with a description of their
experience and certain other information. Each director was elected for a
one-year term at the Company's 2001 annual stockholders' meeting of
stockholders. Officers are appointed by the Board of Directors.

<Table>
<Caption>
OFFICE
HELD
AGE SINCE POSITION
--- ------ --------

E.L. Ames, Jr. 68 1997 Chairman and Chairman of the Board
John Y. Ames 46 1997 President and Director
J.C. Anderson 71 1998 Director
Martin A. Bell 50 1997 Director
James W. Gorman 71 1997 Director
Michael E. Little 47 1999 Director
Jere W. McKenny 73 1997 Director
John H. Pinkerton 48 1997 Director
P. Mark Stark 47 2000 Chief Financial Officer
Terry F. Hardeman 61 2000 Secretary, Treasurer and Chief Accounting Officer
</Table>

EUGENE L. AMES, JR., became Chairman, Chief Executive Officer and a
director of Venus Exploration following its acquisition of the assets and
liabilities of The New Venus Exploration, Inc. ("New Venus") in 1997. He is a
member of Venus Exploration's Executive Committee. He is the father of John Y.
Ames. He has been in the oil and gas business since 1955 and had been associated
with New Venus and its predecessor entities since 1962 and chief executive
officer of those predecessor entities since 1991. He graduated from the
University of Texas at Austin in 1955 with a B.S. degree in Geology. He served
from 1991-93 as the Chairman of the Independent Petroleum Association of
America, the national trade group representing independent oil and natural gas
producers in Washington, D.C., and he currently serves as a member of the Policy
Committee of the American Petroleum Institute (API) and as Chairman of the Texas
Oil and Gas Association. He is also the Chairman of the Board of Directors of
Southwest Research Institute.

JOHN Y. AMES, became President, Chief Operating Officer and a director
of Venus Exploration following the acquisition of New Venus in 1997. He is a
member of Venus Exploration's Executive Committee. He had been associated with
New Venus and its predecessor entities as Vice President since 1984. He became
Executive Vice President of those predecessor entities in 1995 and President and
Chief Operating Officer in 1996. He is the son of Eugene L. Ames, Jr. He
graduated from the University of Texas at Austin in 1978 with a B.B.A. in
Petroleum Land Management.

J.C. ANDERSON, was the Chairman and Chief Executive Officer of Anderson
Exploration, Ltd., a public oil and gas exploration and development company
based in Canada, until it was sold to Devon Energy in October 2001. He founded
Anderson Exploration, Ltd., as a private company in 1968 was employed by it
until the sale. Mr. Anderson intends to stay active in the oil and gas business
in Canada. Mr. Anderson has been a director of Venus Exploration since 1998. He
holds a B.S. in Petroleum Engineering from the University of Texas at Austin and
has more than 40 years experience in the oil and gas business.

MARTIN A. BELL, is the Vice Chairman and General Counsel of D. H. Blair
Investment Banking Corp., New York, New York, and has been a senior officer of
that organization and predecessor companies since 1991. D. H. Blair Investment
Banking Corp. is a member of the New York Stock Exchange. Mr. Bell has been a
director of Venus Exploration since 1997. He is chairman of Venus Exploration's
Audit Committee. Mr. Bell is also a director of News Communications, Inc.

JAMES W. GORMAN, became a director of Venus Exploration following the
acquisition of New Venus in 1997. He is a member of the Compensation and Audit
Committees. He is a petroleum geologist and has been engaged in the oil and gas
business either as a drilling contractor or independent producer for 43 years.
He is currently, and has been for more than 5 years, an independent investor in
various ventures, including exploration and development of oil and gas
properties. He is

President of Cockfield Exploration, Inc., a closely-held oil and gas company
based in San Antonio, Texas. He also serves as a member of the Board of
Directors of Cullen Frost Bancshares Corporation, a bank holding company (NYSE).

MICHAEL E. LITTLE, has been employed as Chairman and Chief Executive
Officer of Pioneer Drilling Company, Inc.(AMEX: PDC), an oil and gas drilling
company based in San Antonio, Texas, since 1999. From 1982 until 1998 he was
President and Chairman of the Board of Dawson Production Services, Inc.(NYSE:
DPS), a well servicing company based in San Antonio, Texas. He has more than 24
years of experience in oil and gas operations management, including six years as
a drilling foreman and engineer. He is a graduate of Texas Tech University with
a B.S. Degree in Petroleum Engineering. He became a director of Venus
Exploration in 1999. Venus Exploration also retains him as a consultant. He is a
member of Venus Exploration's Executive and Compensation Committees.

JERE W. MCKENNY, became a director of Venus Exploration following the
acquisition of New Venus in 1997. He is a member of the Audit and Compensation
Committees. He has been President of McKenny Energy Co., an oil and gas
exploration company based in Oklahoma City, Oklahoma, since September 1994. In
1977, he became a director and the Vice Chairman of the Board of Kerr-McGee
Corp., an oil and gas exploration company based in Oklahoma City, Oklahoma, and
from 1984 until 1993, he also was President and Chief Operating Officer of
Kerr-McGee Corp.

JOHN H. PINKERTON, became a director of Venus Exploration following the
acquisition of New Venus in 1997. He has been employed by Range Resources
Corporation (formerly Lomak Petroleum, Inc.), an independent oil and gas
operating company based in Fort Worth, Texas since 1988, of which he was
appointed President in 1990 and Chief Executive Officer in 1992. He is a
director of Range Resources Corporation. Prior to joining Range Resources, he
was Senior Vice President of Snyder Oil Corporation. He holds a B.A. degree in
Business Administration from Texas Christian University and an M.B.A. from the
University of Texas.

P. MARK STARK, has been the Chief Financial Officer of Venus
Exploration since December 2000. Prior to his association with Venus, he held
the position of Executive Vice President of Alamo Water Refiners, Inc. between
1998 and 2000, and Chief Financial Officer with Dawson Production Services,
Inc.(NYSE: DPS), between 1995 and 1998. He is a graduate of Southern Methodist
University with an M.B.A. in Finance and the University of Texas at Austin with
a B.B.A. degree in Finance and Accounting.

TERRY F. HARDEMAN, has been the Chief Accounting Officer and
Secretary/Treasurer of Venus Exploration since 2000. He has consulted with Venus
Exploration and its predecessors since 1990. He is a graduate of Stephen F.
Austin University with a B.B.A. degree in Accounting and of University of
Houston with a Masters of Business Administration. He is a Certified Public
Accountant in the State of Texas.

The Board has established three committees to assist it in the
discharge of its responsibilities.

Audit Committee. The Audit Committee reviews the professional services
provided by independent public accountants and the independence of such
accountants from management. This Committee also reviews the scope of the audit
coverage, the annual financial statements and such other matters with respect to
the accounting, auditing and financial reporting practices and procedures as it
may find appropriate or as have been brought to its attention. Messrs. Bell,
Gorman and McKenny are the members of the Audit Committee.

Compensation Committee. The Compensation Committee reviews and approves
officers' salaries and administers the bonus, incentive compensation and stock
option plans. The Committee advises and consults with management regarding
benefits and significant compensation policies and practices. This Committee
also considers nominations of candidates for officer positions. The members of
the Compensation Committee are Messrs. Gorman, Little and McKenny.

Executive Committee. The Executive Committee reviews and authorizes
actions required in the management of the business and affairs of Venus, which
would otherwise be determined by the Board, where it is not practicable to
convene the full Board. The members of the Executive Committee are Messrs. Ames,
Jr., Ames and Little.

SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE

Section 16(a) of the Securities Exchange Act of 1934, as amended,
requires the Company's executive officers and directors, and persons who own
more than 10% of a registered class of the Company's equity securities, to file
reports of securities ownership and changes in such ownership with the
Securities and Exchange Commission. Statements of Changes in Beneficial
Ownership of Securities on Form 4 generally are required to be filed by the
tenth day of the month following the

month during which the change in beneficial ownership of securities occurred.
The Company believes that all reports of securities ownership and changes in
such ownership required to be filed during 2001 were timely filed.

ITEM 11. EXECUTIVE COMPENSATION

The following table sets forth the compensation paid by Venus Exploration for
the past three fiscal years to its chief executive officer and its other
executive officers whose salary and bonus exceeded $100,000. At no time during
this period did Venus Exploration pay any other executive officer annual
compensation exceeding $100,000. No compensation information is given for any
person for any year in which that person was not an officer of Venus
Exploration.

SUMMARY COMPENSATION TABLE

<Table>
<Caption>
ANNUAL COMPENSATION SECURITIES ALL OTHER
FISCAL ----------------------- UNDERLYING COMPENSA-
NAME AND POSITION YEAR SALARY($) BONUS ($) OPTIONS (#) TION ($) (1)
----------------- ------ --------- --------- ----------- ------------

Eugene L. Ames, Jr., Chairman & 2001 190,000 -0- -0- 8,569
Chief Executive Officer (2)............. 2000 173,375 -0- 98,517 2,224
1999 138,858 -0- 52,074 2,220

John Y. Ames, President & 2001 142,500 25,000 43,065 7,730
Chief Operating Officer (3).............. 2000 122,841 50,000 35,037 7,138
1999 90,292 -0- 21,898 7,539

P. Mark Stark, 2001 103,924 20,000 100,000 6,256
Chief Financial Officer (4).............. 2000 12,500 -0- 16,842 -0-
</Table>

- ----------

(1) Except as otherwise specified, this amount consists of cash amounts
contributed by Venus Exploration to match a portion of the executive's
contributions under the 401(k) Plan and the costs of group term life
insurance provided to employees and personal use of a company-owned
vehicle.

(2) Eugene L. Ames, Jr., Became Chief Executive Officer on May 21, 1997.

(3) John Y. Ames became President and Chief Operating Officer on May 21,
1997.

(4) P. Mark Stark became Chief Financial Officer on December 12, 2000.

OPTION GRANTS IN FISCAL 2001

<Table>
<Caption>
POTENTIAL REALIZABLE
VALUE-AT-ASSUMED
ANNUAL RATES OF
STOCK PRICE
APPRECIATION FOR
INDIVIDUAL GRANTS OPTION TERM
- ----------------------------------------------------------------------------- --------------------
NUMBER OF % OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO
OPTIONS EMPLOYEES IN EXERCISE EXPIRATION
NAME GRANTED FISCAL YEAR PRICE DATE 5% 10%
---- ---------- ------------ -------- ----------- ------- -------

John Y. Ames ......... 43,065 20.9% $ 0.69 09/27/06 $ 8,210 $18,141
P. Mark Stark ........ 100,000 48.4% $ .63 9/27/11 $19,063 $42,125
</Table>

OPTION EXERCISES AND FISCAL YEAR-END VALUES

The following table shows, for the company's chief executive officer and
the other executive officers named in the Summary Compensation Table, the number
of shares acquired upon the exercise of options during 2001, the amount realized
upon such exercise, the number of shares covered by both exercisable and
non-exercisable stock options as of December 31, 2001, and the values for
"in-the-money" options, based on the positive spread between the exercise price
of any such existing stock options and the year-end price of the common stock.

AGGREGATED OPTIONS EXERCISED IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES

<Table>
<Caption>
NUMBER OF SECURITIES VALUE OF UNEXERCISED
SHARES UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS AT
ACQUIRED ON VALUE OPTIONS AT DECEMBER 31, 2001 DECEMBER 31, 2001 (1)
EXERCISE OF REALIZED($) ----------------------------- ----------------------------
NAME OPTIONS(#) (2) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ------------ ----------- ----------- ------------- ------------ ------------

Eugene L. Ames, Jr ..... -0- $ -0- 190,591 -0- $ -0- $ -0-
John Y. Ames ........... -0- $ -0- 76,965 43,065 $ -0- $ -0-
P. Mark Stark .......... -0- $ -0- 16,842 100,000 $ -0- $ -0-
</Table>

- ----------

(1) Aggregate market value based on December 31, 2001 stock price of $0.56
per share of the shares covered by the options.

(2) Represents the difference between the aggregate exercise price and the
aggregate value, based upon the stock price on the date of exercise.

EMPLOYMENT AGREEMENT WITH CHIEF EXECUTIVE OFFICER

On July 1, 1999, Eugene L. Ames, Jr., entered into a two-year
employment contract with Venus Exploration that established his annual salary at
$190,000 per year and other compensation, including the use of an automobile.
This agreement replaced the three-year agreement that expired on June 1, 1999.
The prior agreement also provided for annual compensation of $190,000. The
employment agreement also included agreements by Eugene L. Ames, Jr. with regard
to confidentiality and noncompetition in order to protect Venus Exploration's
proprietary information. Mr. Ames, Jr.'s employment agreement expired on July 1,
2001 and Mr. Ames, Jr. continues to be paid on a month to month basis under the
same terms as were in place under the agreement, one of which was a non-compete
provision.

Beginning on March 1, 1999, Mr. Ames, Jr. agreed to take a 21.5% salary
reduction, and on May 1, 1999, the salary reduction was increased to 35%. In
return for the salary reduction, on March 1, 1999, Venus Exploration granted Mr.
Ames, Jr.,

options to buy 52,074 shares of Venus Exploration's common stock, and on August
1, 1999, it granted him options to acquire another 98,517 shares. All of those
options are now fully vested. The exercise price for the first set of options is
$1.23, which was 110% of the fair market value of a share of the common stock on
the date of grant of those options. They expire on February 28, 2004, and they
vested in semi-monthly increments beginning March 1, 1999. The exercise price
for the second set of options is $1.152, which was 110% of the fair market value
of a share of the common stock on the date of grant of those options. Those
options will expire on December 12, 2005, and they vested contingently in
semi-monthly increments beginning August 1, 1999. The contingency was
shareholder approval of the increase in the number of shares subject to the 1997
Incentive Plan which was approved at the Company's 2000 Annual Meeting.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

The Compensation Committee of the Board of Directors currently consists
of James W. Gorman, Michael E. Little and Jere W. McKenny. No member of the
Compensation Committee was, during fiscal 2001, an officer or employee of Venus
Exploration or any of its subsidiaries, nor was any member of the Compensation
Committee formerly an officer of Venus Exploration or any of its subsidiaries.
However, Mr. Little serves as a consultant to Venus Exploration under an
agreement that was entered into before he began serving on the Compensation
Committee. During fiscal year 2001, no executive officer of the Company served
either as:

o a member of the compensation committee or board of directors
of another entity, one of whose executive officers served on
the Compensation Committee, or

o a member of the compensation committee of another entity, one
of whose executive officers served on Venus Exploration's
Board of Directors.

COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION

Currently, decisions on compensation of Venus Exploration's executive
officers are made by the Compensation Committee of the Board of Directors. The
following addresses Venus Exploration's executive officer compensation policies
for 2001.

GENERAL. Venus Exploration's compensation program is designed to enable
Venus Exploration to attract, to motivate and to retain high quality senior
management by providing a competitive total compensation opportunity based on
performance. To this end, Venus Exploration provides for base salaries, bonuses
based on subjective factors and stock-based incentives that strengthen the
mutuality of interests between employees and Venus Exploration's stockholders.

SALARIES. Eugene L. Ames, Jr.'s salary through June 30, 2001 was
provided for in an employment agreement. The material terms of Eugene L. Ames,
Jr.'s employment agreement are described above under the caption "Employment
Agreement with Chief Executive Officer.". Mr. Ames, Jr.'s employment agreement
expired on July 1, 2001 and Mr. Ames, Jr. continues to be paid on a month to
month basis under the same terms as were in place under the agreement, one of
which was a non-compete provision.

Salaries of the executive officers were determined based upon the level
of responsibility, time with Venus Exploration, and the contribution and
performance of the particular executive officer. Evaluation of these factors was
subjective, and no fixed or relative weights were assigned to the factors
considered. Because of the economic conditions in the oil and natural gas
industry and the impact upon Venus Exploration's performance, Venus Exploration
reduced the salaries of its executive officers beginning in March of 1999. These
salary reductions range from between 21.5% to 35%, and they have been partially
offset by the grant of additional stock options to Venus Exploration's executive
officers. On or about March 31, 2000, Venus Exploration reinstated the prior
levels of salary compensation.

BONUS COMPENSATION. Through the use of annual bonuses, Venus
Exploration seeks to effectively tie executive compensation to Venus
Exploration's performance. The Compensation Committee granted some bonuses
during 2001 based on the discretion of the Compensation Committee, taking into
account, among other factors, the financial performance of Venus Exploration.

OPTIONS AND RESTRICTED STOCK GRANTS. Venus Exploration uses grants of
stock options and restricted stock to its key employees and executive officers
to closely align the interests of such employees and officers with the interests
of its stockholders. The 1997 Incentive Plan is administered by the Compensation
Committee, which determines the persons eligible for awards, the number of
shares subject to each grant, the exercise price of options and the other terms
and conditions of the grants of options or restricted stock.

THE COMPENSATION COMMITTEE
Jere W. McKenny
James W. Gorman
Michael E. Little

DIRECTOR COMPENSATION

Directors of Venus Exploration are compensated under the 1997 Incentive
Plan. Under the 1997 Incentive Plan, non-employee directors receive (a) $12,000
per year, and (b) $500 per board meeting attended, whether in person or by
phone. Such payments are made in the form of grants of shares of common stock
or, at the option of a director, a combination of Venus Exploration's common
stock and cash. In the case of the second option, the cash compensation is
limited to a maximum of 25% of the $12,000 per year.

FIVE-YEAR STOCKHOLDER RETURN COMPARISON

Set forth below is a line graph comparing, for the five (5)-year period
ended December 31, 2001, the yearly percentage change in the cumulative total
stockholder return on the Venus Exploration common stock with that of (a) all
U.S. companies quoted on the Nasdaq Market Index and (b) the SIC Code Index for
crude petroleum and natural gas stocks. The stock price performance shown on the
graph below is not necessarily indicative of future price performance.

[PERFORMANCE GRAPH]

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURNS*
AMONG VENUS EXPLORATION INC.,(1)
SIC CODE INDEX AND NASDAQ MARKET INDEX

<Table>
<Caption>
COMPANY 1997 1998 1999 2000 2001
- ------- ------ ------ ------ ------ ------

Venus Exploration, Inc. 164.71 64.71 64.71 45.59 26.35
Industry Index 93.80 60.07 86.93 75.58 97.61
Broad NASDAQ Market 122.50 169.84 313.65 191.36 151.07
</Table>

* $100 INVESTED ON 12/31/96 IN STOCK OR INDEX, INCLUDING REINVESTMENT OF
DIVIDENDS.

(1) Stock prices shown for dates prior to May 21, 1997 are attributable
to Xplor Corporation, and its financial history is not contained in Venus
Exploration's Annual Report on Form 10-K for the year ended December 31, 2001.
Therefore, comparisons of the stock price history with other historical
financial data for the period before May 21, 1997 is misleading.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the information as of December 31, 2001,
regarding the shares of common stock owned and shares of common stock issuable
upon exercise or conversion of outstanding options, warrants or convertible
securities that can be exercised or converted by their terms on or before March
31, 2002, by (a) each person, including any group, who is known by management to
be the beneficial owner of more than 5% of the common stock as of such date, (b)
each director and director nominee, (c) Venus Exploration's executive officers,
and (d) all directors and executive officers as a group based upon shares of
common stock outstanding on such date.

<Table>
<Caption>
AMOUNT & NATURE OF
BENEFICIAL OWNERSHIP PERCENT OF
DIRECTORS, NOMINEES AND EXECUTIVE OFFICERS (1) CLASS
- ------------------------------------------ -------------------- ----------

Eugene L. Ames, Jr. .............................. 2,028,604(2) 16.09%
John Y. Ames ..................................... 468,682(3) 3.75%
J. C. Anderson ................................... 48,259 *
Martin A. Bell ................................... 99,388(4) *
James W. Gorman .................................. 364,474 2.94%
Michael E. Little ................................ 341,798 2.75%
Jere W. McKenny .................................. 87,261 *
John H. Pinkerton ................................ -0-(5) *
P. Mark Stark .................................... 18,842(6) *
Terry F. Hardeman ................................ 7,334(7) *

Directors and Executive Officers as a group
(10 persons) .................................... 3,464,642 27.20%
</Table>

<Table>
<Caption>
AMOUNT & NATURE OF
BENEFICIAL OWNERSHIP PERCENT OF
NAME AND ADDRESS OF FIVE PERCENT SHAREHOLDERS (1) CLASS
- --------------------------------------------- -------------------- ----------

Eugene L. Ames, Jr.
1250 NE Loop 410, Suite 810
San Antonio, TX 78209 ........................... 2,028,604(2) 16.09%

J. Morton Davis
44 Wall Street
New York, NY 10005 .............................. 1,049,139(4) 8.45%

Range Resources Corporation
500 Throckmorton Street
Fort Worth, TX 76102 ............................ 2,166,213(5) 17.55%

Mustang Drilling, LTD.
101 West Fordall
Henderson, TX 75652 .............................. 1,020,230(8) 8.22%
</Table>

- ----------

* Less than one percent (1%).

(1) All persons named have sole voting and investment power, except as
otherwise noted.

(2) Includes (a) 289,690 shares and 190,591 exercisable options owned by
Eugene L. Ames, Jr.; (b) 1,140,399 shares, or 9.18% of the common
stock, owned by Ellen R. Y. Ames, the spouse of Eugene L. Ames, Jr.;
and (c) 407,924 shares owned by Venus Oil Company, which is controlled
by Mr. and Mrs. Eugene L. Ames, Jr.

(3) Includes exercisable options to purchase 76,935 shares.

(4) Includes 30,000 exercisable options. The data with respect to Mr. Bell
excludes shares owned by his employer, and Mr. Bell disclaims
beneficial ownership of his employer's shares. J. Morton Davis owns Mr.
Bell's employer, and that entity is deemed to own 1,049,139 shares.

(5) The data with respect to Mr. Pinkerton does not reflect the 2,166,213
shares that are beneficially owned by Range Resources Corporation, of
which Mr. Pinkerton is President. Mr. Pinkerton disclaims beneficial
ownership of such shares.

(6) Includes exercisable options to purchase 16,842 shares.

(7) Includes exercisable options to purchase 7,334 shares.

(8) Mustang Drilling, Ltd. has sole voting power for 888,830 shares.
Michael T. Wilhite, Sr. has sole voting power for 72,000 shares, Andrew
D. Mills has sole voting power for 59,400 shares and Michael T.
Wilhite, Jr. has sole voting power for 0 shares. Each has shared voting
power for 1,020,230.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

EUGENE L. AMES, JR.

Venus Exploration currently operates approximately four (4) wells,
projects and prospects in which Venus Oil Company owns a royalty interest. Venus
Oil Company is owned by Mr. Ames, Jr., and his immediate family. Those family
members include his son, John Y. Ames, and his daughter, Elizabeth Ames Jones,
wife of Will C. Jones IV, who is discussed below. Venus Oil Company received
$1,573 last year in proceeds from wells and projects operated by Venus
Exploration.

COCKFIELD EXPLORATION COMPANY

Venus Exploration currently operates approximately forty (40) wells,
projects and prospects in which Cockfield Exploration Company owns an interest.
Cockfield Exploration Company is owned by Mr. James W. Gorman, who has been a
director of Venus Exploration or its predecessors since June 1996. All wells and
prospects in which Cockfield Exploration has participated since Mr. Gorman
became a director are operated under project agreements or joint operating
agreements entered into prior to Mr. Gorman becoming a director of the company.
During 2001, Cockfield Exploration Company paid Venus Exploration $24,913 for
its share of joint costs. Cockfield Exploration Company received $44,116 last
year in proceeds from wells and projects operated by Venus Exploration.

WILL C. JONES, IV

Will C. Jones, IV, is the son-in-law of Eugene L. Ames, Jr., and the
brother-in-law of John Y. Ames. He is currently a shareholder of Earl & Brown,
P.C. Mr. Jones and Earl & Brown, P.C. provide legal counsel to Venus
Exploration. In 2002, Venus Exploration expects to pay Earl & Brown, P.C. in
excess of $60,000 for such services. During 2001, Mr. Jones was of counsel to
Lindow & Treat, LLP, and Venus Exploration paid fees of $110,847 for the
services of Mr. Jones and others in that firm and Earl & Brown, P.C.

RANGE RESOURCES CORPORATION

Range Resources Corporation owns a 15% working interest in the Venus
Westbury Farms #1 well and in the Venus-Apache Gas Unit Well #1. Both of those
wells are in the Constitution Field in Jefferson County, Texas. Mr. John H.
Pinkerton is the president and chief executive officer of Range Resources, and
he has been a director of Venus Exploration since May 1997. The Westbury Farms
well was completed in early 1998 with sales commencing in late August 1998. The
Venus-Apache Gas Unit Well #1 was completed in September 2000. Range Resources
participated on the same basis, adjusted for size of working interest, as other
non-operators. During 2001 Range Resources paid Venus Exploration $1,121,605 for
its share of joint costs, and it received $918,926 in 2001 as proceeds from the
Westbury Farms #1 well.

JAMES W. GORMAN AND MICHAEL E. LITTLE - REGISTRATION RIGHTS AGREEMENTS

Concurrently with the issuance of certain 7.0% Convertible Subordinated
Promissory Notes (the "Subordinated Notes") in 1999, the Company entered into
registration rights agreements with each noteholder, including Messrs. Gorman
and Little. The registration rights agreements gave the noteholders the option
to register for resale under the Securities Act of 1933 the shares of the
Company's common stock that they would receive upon conversion of the such
Subordinated Notes. The Subordinated Notes were converted by all of the
noteholders into shares of the Company's Common Stock in June 2000. Pursuant to
the terms of the registration rights agreements, the registration would only be
on a registration statement otherwise being filed by the Company for sales on
its own behalf. The Company Exploration also agreed not to grant any new
registration rights to third parties if those rights would adversely impact the
rights of the holders of the Subordinated Notes described above.

MICHAEL E. LITTLE

Beginning April 1, 1999, Michael E. Little, a director of Venus
Exploration, was engaged by the company as a consultant. He provides advice and
assistance in financial and organizational matters. The company pays him $3500
per month and reimburses him for his expenses incurred on behalf of the company.
The relationship may be terminated by either party upon thirty (30) days notice.

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)

*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 (incorporated by reference
to Exhibit 10.3 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000)

*10.4 Form of Registration Rights Agreement executed in conjunction with 7%
Convertible Subordinated Notes (incorporated by reference to Exhibit
10.5 to the Company's Quarterly Report on Form 10-Q for the period June
30, 1999)

*+10.5 Executive Employment Agreement dated July 1, 1999, between the Company
and 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)

*10.6 Loan Agreement dated May 5, 2000, between the Company and Bank One,
Texas, N.A. (incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the period ended March 31, 2000)

*10.7 First Amendment to the Loan Agreement dated May 5, 2000, by and between
the Company and Bank One Texas, N.A. (incorporated by reference to
Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 2000)

*+10.8 Consulting Agreement effective October 30, 2000, between the Company
and P. Mark Stark (incorporated by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 2000)

*10.9 Forbearance Agreement and Second Amendment to Loan Agreement Dated May
5, 2001, by and between the Company and Bank One, Texas, N.A.
(incorporated by reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the period ended June 30, 2001)

*10.10 Loan Agreement (Line of Credit) dated as of July 6, 2001, by and
between the Company and Hibernia National Bank (incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 2001)

10.11 Waiver and Amendment dated as of December 11, 2001, by and between the
Company and Hibernia National Bank (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.

Form 8-K dated November 21, 2001.

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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

VENUS EXPLORATION, INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<Table>
<Caption>
PAGE

Independent Auditors' Report F-2

Consolidated Balance Sheets as of
December 31, 2001 and 2000 F-3

Consolidated Statements of Operations for
Each of the years in the three-year period
Ended December 31, 2001 F-4

Consolidated Statements of Shareholders' Equity and Comprehensive
Income for each of the years in the three-year period
Ended December 31, 2001 F-5

Consolidated Statements of Cash Flows for each of the
Years in the three-year period ended December 31, 2001 F-6

Notes to Consolidated Financial Statements F-7
</Table>

F-1

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, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States of America.

As described in Note 2 to the consolidated financial statements, as of January
1, 2001, the Company changed its method of accounting for derivative instruments
and hedging activities.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 14 to the
financial statements, the Company has suffered recurring losses from operations
and has a working capital deficiency and a net capital deficiency that raise
substantial doubt about its ability to continue as a going concern. Management's
plans in regard to these matters are also described in Note 14. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.

KPMG LLP

March 22, 2002,
San Antonio, Texas

F-2

VENUS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

<Table>
<Caption>
DECEMBER 31,
----------------------------
2001 2000
------------ ------------

ASSETS
Current assets:
Cash and equivalents $ 430,515 $ 1,086,035
------------ ------------
Trade accounts receivable, net 1,861,155 1,034,375
Prepaid expenses and other 83,614 73,461
------------ ------------
Total current assets 2,375,284 2,193,871
Oil and gas properties and equipment, at cost
under the successful efforts method, net 6,686,285 4,783,125
Other property and equipment, net 150,696 93,644
Deferred financing costs, at cost less accumulated amortization 147,060 30,813
Other assets, at cost less accumulated amortization 32,814 15,730
------------ ------------
$ 9,392,139 $ 7,117,183
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable $ 8,037,712 $ 3,435,011
Other liabilities 933,954 464,062
Current notes payable 1,254,351 1,130,000
------------ ------------
Total current liabilities 10,226,017 5,029,073
Other long-term liabilities 28,008 13,085
------------ ------------
Total liabilities 10,254,025 5,042,158
Shareholders' equity (deficit):
Preferred stock; par value of $.01; 5,000,000 shares
authorized; none issued and outstanding -- --
Common stock; par value of $.01; 50,00,000 shares
authorized; 12,441,375 and 12,341,065 shares issued,
and 12,414,495 and 12,314,185 shares outstanding in 2001 and
2000, respectively 124,414 123,411

Additional paid-in capital 18,815,374 18,721,312
Accumulated deficit (19,761,432) (16,710,706)
Less cost of treasury stock (26,880 shares) (40,242) (40,242)
Unearned compensation -- (18,750)
------------ ------------
Total shareholders' equity (deficit) (861,886) 2,075,025
Commitments and contingencies $ 9,392,139 $ 7,117,183
============ ============
</Table>

See accompanying notes to consolidated financial statements.

F-3

VENUS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
--------------------------------------------
2001 2000 1999
------------ ------------ ------------

Oil and gas revenues $ 3,302,250 $ 3,718,364 $ 2,183,681
------------ ------------ ------------
Costs of operations:
Production expense 1,487,701 1,456,334 1,025,947
Exploration expenses, including dry holes 1,338,385 1,159,132 664,581
Impairment of oil and gas properties 276,435 -- 544,740
Depreciation, depletion and amortization 1,019,863 694,743 663,236
General and administrative 2,184,506 1,894,204 2,291,017
------------ ------------ ------------
Total expenses 6,306,890 5,204,413 5,189,521
------------ ------------ ------------
Operating loss (3,004,640) (1,486,049) (3,005,840)
------------ ------------ ------------
Other income (expense):
Interest expense (225,444) (169,217) (895,602)
Equity in net earnings from EXUS Energy, LLC -- -- 444,968
Debt conversion expense -- (235,451) --
Gain on sale of assets 184 598,502 4,762,170
Interest and other income 179,174 25,905 33,888
------------ ------------ ------------
(46,086) 219,739 4,345,424
------------ ------------ ------------
Net income (loss) before income taxes and extraordinary item (3,050,726) (1,266,310) 1,339,584
Income tax expense -- -- 330,000
------------ ------------ ------------
Income (loss) before extraordinary item (3,050,726) (1,266,310) 1,009,584
Extraordinary loss on early extinguishment of debt -- (250,000) --
------------ ------------ ------------
Net income (loss) $ (3,050,726) $ (1,516,310) $ 1,009,584
============ ============ ============

Basic and diluted earnings (loss) per share:
Earnings (loss) before extraordinary item $ (.25) $ (.11) $ 0.09
Extraordinary loss on early extinguishment of debt -- (.02) --
------------ ------------ ------------
Earnings (loss) $ (.25) $ (.13) $ 0.09
============ ============ ============

Common shares and equivalents outstanding:
Basic 12,373,642 11,666,444 11,011,218
============ ============ ============

Diluted 12,373,642 11,666,444 11,579,723
============ ============ ============
</Table>

See accompanying notes to consolidated financial statements.

F-4

VENUS EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
AND COMPREHENSIVE INCOME

<Table>
<Caption>
Accumu-
lated other
Additional Retained Compre-
Issued Common Paid-in Treasury Earnings hensive Unearned
Shares Stock capital Stock (deficit) Income Compensation Total
----------- -------- ----------- -------- ------------ ------------ ------------ ----------

Balances,
December 31, 1998 10,971,325 $109,713 $17,209,042 $ -- $(16,203,980) $ -- (243,750) $ 871,025
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 to
common stock 1,142,854 11,429 1,217,452 -- -- -- -- 1,228,881
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

Net Loss -- -- -- -- (3,050,726) -- (3,050,726)

Unrealized loss on
derivative instruments (334,000) (334,000)
upon adoption of SFAS
No. 133

Reclassification
adjustments for loss
recognized 334,000 334,000
----------
Comprehensive loss (3,050,726)

Compensation cost
for stock and
stock options 100,310 1,003 94,062 -- -- -- -- 95,065

Earned compensation -- -- -- -- -- -- 18,750 18,750
----------- -------- ----------- -------- ------------ ------------ ------------ ----------
Balances
December 31, 2001 12,441,375 $124,414 $18,815,374 $(40,242) $(19,761,432) $ -- $ -- $ (861,886)
=========== ======== =========== ======== ============ ============ ============ ==========
</Table>

See accompanying notes to consolidated financial statements.

F-5

VENUS EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
--------------------------------------------
2001 2000 1999
------------ ------------ ------------

Operating Activities:
Net earnings (loss) $ (3,050,726) $ (1,516,310) $ 1,009,584
Adjustments to reconcile net loss to net cash used in
operating activities:
Depreciation, depletion and amortization of oil and gas
properties 1,019,863 694,743 663,236
Other depreciation and amortization 508,084 151,181 147,388
Impairments, abandoned leases, and dry hole costs 1,002,390 195,864 593,470
Gain on sale of property and equipment -- (598,502) (4,762,170)
Debt and option conversion expense -- 228,881 --
Equity in net earnings of EXUS -- -- (444,968)
Loss on early extinguishment of debt -- 250,000 --
Compensation expense for stock and stock options 113,814 225,647 213,770
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 (826,780) (316,411) (303,269)
Prepaid expenses and other (27,237) 986 (12,878)
Trade accounts payable 4,602,700 1,987,092 179,177
Other liabilities 136,170 (603,071) 633,577
------------ ------------ ------------
Net cash provided by (used in) operating
activities 3,478,278 684,094 (1,984,406)
------------ ------------ ------------
Investing Activities:
Capital expenditures (4,046,465) (1,542,891) (584,815)
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
------------ ------------ ------------
Net cash provided by (used in) investing
activities (4,046,465) 18,084,073 (4,900,653)
------------ ------------ ------------
Financing Activities:
Net proceeds from issuance of long-term debt and notes
payable 2,339,796 3,678,609 9,063,495
Principal payments on long-term debt and notes (2,200,522) (21,223,371) (2,038,239)
payable
Deferred financing costs (226,607) (82,801) (30,356)
Proceeds from issuance of stock -- -- --
Prepayment penalty on early extinguishment of debt -- (250,000) --
Purchase of treasury stock -- (40,242) --
------------ ------------ ------------
Net cash provided by (used in) financing
activities (87,333) (17,917,805) 6,994,900
------------ ------------ ------------
Increase (decrease) in cash and equivalents (655,520) 850,362 109,841
Cash and equivalents, beginning of year 1,086,035 235,673 125,832
------------ ------------ ------------
Cash and equivalents, end of year $ 430,515 $ 1,086,035 $ 235,673
============ ============ ============
</Table>

See accompanying notes to consolidated financial statements.

F-6

VENUS EXPLORATION, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2001 AND 2000

(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.

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.

(d) Other Property and Equipment

F-7

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, 2001 and 2000, there were no
significant imbalances. Three customers accounted for approximately
19%, 17% and 14% of total consolidated revenues for the year ended
December 31, 2001. 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.

Accounts receivable at December 31, 2001 and 2000 are net of an
allowance for doubtful accounts of $108,800 and $ 36,600 respectively.

(g) Deferred Financing Costs

Deferred financing costs consist of costs associated with obtaining
the Company's debt agreements, as discussed in Note 5, which are
amortized over the expected term of the related borrowings.

(h) Hedging Transactions

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 delayed the required
adoption of FAS 133 to fiscal 2001. The Company adopted SFAS No. 133
effective January 1, 2001. Under the transition provisions of SFAS No.
133, on January 1, 2001 the Company recorded 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. 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.

On September 28, 2001, we entered into commodity collar agreements for
112 barrels of oil per day for the six month period from November 1,
2001 though April 30, 2002. The oil hedge is a costless collar with a
floor of $22.20 per barrel and a ceiling of $24.50 per barrel. If the
average NYMEX price is less than $22.20 for any month, we receive the
difference between $22.20 and the average NYMEX price for that
particular month. If the average NYMEX price is greater than $24.50
for any month, we pay

F-8

the difference between $24.50 and the average NYMEX price for that
particular month. 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 December 31, 2001.
Future changes in the fair value of those derivatives will be recorded
in income. We entered into this costless collar with Enron North
America Corp ("Enron"). Since we have a receivable from Enron in the
amount of $18,209 at December 31, 2001, we have recorded a provision
for bad debts in the same amount.

(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 that 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 2000 and 2001 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

<Table>
<Caption>
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
============
</Table>

(o) Recent Accounting Pronouncements

Statement of Financial Accounting Standards ("SFAS") No. 141, "Business
Combinations," issued in June 2001, establishes accounting and reporting
standards for business combinations. This statement eliminates the
pooling-of-interests method of accounting for business combinations and
requires all business combinations to be accounted for using the purchase
method. The Company adopted SFAS No. 141 on July 1, 2001. The adoption of
SFAS No. 141 did not have an effect on the Company's financial statements.

SFAS No. 142, "Goodwill and Other Intangible Assets," issued in June, 2001,
establishes accounting and reporting standards for acquired goodwill and
other intangible assets. This statement addresses how goodwill and other
intangible assets that are acquired or have already been recognized in the
financial statements should be accounted for. Under this statement goodwill
and certain other intangible assets will no longer be amortized, but will
be required to be reviewed periodically for impairment of value. The
Company will adopt SFAS No. 142 on January 1, 2002. The adoption of SFAS
No. 142 is not expected to have a material impact on the Company's
financial statements.

SFAS No. 143, "Accounting for Asset Retirement Obligations," issued in June
2001, significantly changes the method of accruing for costs associated
with the retirement of fixed assets (e.g. oil and gas production
facilities, etc.) for which an entity is legally obligated to incur. The
Company will evaluate the impact and timing of implementing SFAS No. 143.
Implementation of this standard is required no later than January 1, 2003,
with earlier adoption encouraged.

SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," issued in August 2001, addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. This
statement supercedes SFAS No. 121, "Accounting for the Impairment of Long
Lived Assets to Be Disposed Of". However, it retains the fundamental
provisions of Statement 121 for (a) recognition and measurement of the
impairment of the impairment of long-lived assets to be held, and used and
(b) measurement of long-lived assets to be disposed of by sale. The Company
is required and plans to adopt the provisions of SFAS No. 144 beginning on
January 1, 2002. The Company believes the adoption of SFAS No. 144 will not
have a material impact on the Company's financial statements.

F-10

(3) OIL AND GAS PROPERTIES

Oil and gas properties consist of the following at December 31, 2001 and
2000:

<Table>
<Caption>
2001 2000
------------ ------------

Proved properties $ 10,710,728 $ 8,685,387
Unproved properties 945,612 116,360
------------ ------------
11,656,340 8,801,747
Less accumulated depreciation, depletion and amortization (4,970,055) (4,018,622)
------------ ------------
$ 6,686,285 $ 4,783,125
============ ============
</Table>

The impairment of oil and gas properties recognized in 2001 includes a net
write-down of proved properties of approximately $276,435 (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.

(4) OTHER PROPERTY AND EQUIPMENT

Other property and equipment consists of the following at December 31, 2001
and 2000:

<Table>
<Caption>
2001 2000
--------- ---------

Transportation equipment $ -- $ 6,293
Furniture, fixtures and office equipment 556,342 556,234
Geophysical interpretation system 118,516 118,516
--------- ---------
674,858 681,043
Less accumulated depreciation, depletion and amortization (524,162) (587,399)
--------- ---------
$ 150,696 $ 93,644
========= =========
</Table>

(5) NOTES PAYABLE

Notes payable consists of the following at December 31, 2001 and 2000:

<Table>
<Caption>
2001 2000
---------- ----------

Revolving credit $1,254,351 $1,130,000
========== ==========
</Table>

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.

F-11

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 year ended December 31, 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 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.

Hibernia National Bank

On July 6, 2001 (the "Loan Closing Date"), we entered into a new Loan
Agreement with a bank that was initially for a two year, $5,000,000
revolving line of credit. The line of credit is subject to a borrowing base
based on oil and gas reserves to be redetermined by the bank at any time
but must be evaluated every six months. We may request a redetermination
one time per year. The initial borrowing base under this Loan Agreement was
$2,000,000, with reductions of $50,000 per month during the term of the
facility. The $1,130,000 outstanding under the our old line of credit was
repaid through advances under this new line of credit with the bank. We are
using the remaining facility for acquisition and development of oil and gas
properties and for general working capital purposes, including letters of
credit. The facility initially bore interest at either the Wall Street
Journal Prime Rate plus the applicable Prime Rate Margin (250 basis points
if more than two-thirds (2/3) of the commitment was outstanding, and zero
basis points if less) or the Eurodollar Rate (LIBOR) plus the applicable
LIBOR Margin, at the option of the Company. Eurodollar Rate credit facility
pricing varied from LIBOR + 225 basis points if less than one-third of the
commitment was outstanding, to LIBOR + 250 basis points for one-third to
two-thirds of the commitment, to LIBOR + 275 basis points if greater than
two-thirds of the commitment was outstanding. As of December 11, 2001, we
entered into an amendment of our current credit facility whereby the
interest rate was increased to the Wall Street Journal Prime Rate plus 200
basis points, and the revolving line of credit and the borrowing base were
each reduced to $1,900,000. In conjunction with a sale of oil and gas
properties that occurred on January 31, 2002, we entered into another
amendment to the current credit facility where the term of the loan
agreement was changed from July 5, 2003 to June 30, 2002, and the revolving
line of credit and the borrowing base were each reduced to $1,850,000. As
of March 18, 2002, we entered into an amendment of our current credit
facility whereby the revolving line of credit was reduced to $938,454 and
the borrowing base was reduced to $938,454, with reductions to such
borrowing base of $50,000 per month during the term of the facility, and an
additional reduction of $100,000 to occur on April 2, 2002, upon the
expiration of a letter of credit. As of March 30, 2002, our current credit
facility has a revolving line of credit of $938,454 and a borrowing base of
$938,454, and will expire on June 30, 2002.

Interest is payable monthly for balances bearing interest using the Prime
Rate, and either monthly, bi-monthly or quarterly (depending on the
interest period selected by the Company) for balances bearing interest
using the Eurodollar Rate.

F-12

The facility is secured by all of the Company's oil and gas properties, and
contains the following financial covenants:

(2) Minimum Net Worth. The Company shall have a net worth of not less than
$1,866,600 on the Loan Closing Date, and thereafter shall maintain, on
a quarterly basis as of the last day of each fiscal quarter, the
minimum net worth requirement that shall be re-set annually after the
end of each year. For purposes of this covenant, such number shall be
adjusted to exclude non-cash items, including unrealized gains and
losses, arising from the effects, if any, of the mark to market of
those Hedging Obligations which are classified as cash flow hedges and
determined "effective" pursuant to FASB Rule 133, or of other rules
pertaining to other comprehensive income.

The facility contains other usual and standard covenants such as: debt and
lien restrictions; dividend and distribution prohibitions; restriction on
changes in key management and financial statement reporting requirements.
The credit facility also requires that the Company hedge at least 25% of
its daily oil and gas production for twelve months.

As of December 31, 2001, the Company was not in compliance with certain of
its loan covenants; however, the Company sought and received waivers for
its non-compliance with those loan covenants. In order for the Company to
achieve compliance with its loan covenants in the future, the Company needs
to raise additional capital and/or obtain amendment of certain loan
covenants.

In conjunction with the Company' costless collar contract that was entered
into as a requirement of its Loan Agreement, the Company had to give Enron
a letter of credit ("L/C") in the amount of $100,000 with Enron as the
beneficiary of the L/C. The L/C expires on April 1, 2002 and the Company
and its current lender do not intend to renew the L/C.

(6) INCOME TAXES

No provision for federal income taxes has been recorded in the accompanying
financial statements for the year ended December 31, 2001 due to the losses
recorded by the Company. For the year ended December 31, 2000, no provision
was recorded due to the availability of net operating loss carryforwards.

The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31, 2001 and 2000 are presented below:

F-13

<Table>
<Caption>
2001 2000
----------- -----------

Deferred tax assets:
Oil and gas and other property and
equipment, principally due to differences
in depreciation, depletion, and amortization $ 74,000 $ 241,000
Net operating loss carryforwards 5,528,000 4,255,000
Depletion carryforwards 516,000 330,000
Other 5,000 16,000
----------- -----------
Total gross deferred tax assets 6,123,000 4,842,000
Less valuation allowance
(6,123,000) (4,842,000)
----------- -----------
Net deferred tax assets $ -- $ --
=========== ===========
</Table>

The valuation allowance for deferred tax assets as of December 31, 2001 and
2000 was $6,123,000 and $4,842,000, respectively. The net change in the
total valuation allowance for the years ended December 31, 2001 and 2000
was an increase of $1,281,000 and $669,000, 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, 2001 and 2000 has been offset entirely by a
valuation allowance due to the uncertainty of the ultimate realization of
such benefits.

As of December 31, 2001, the Company has an estimated net operating loss
carryforward for U.S. federal income tax purposes of approximately
$14,900,000 which is available to offset future taxable income, if any.
These net operating loss carryforwards expire in various years, beginning
in 2013, through 2021.

(7) 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, 2001, Venus Oil Company owed
the Company $594 while at December 31, 2000, Venus Oil Company owed the
Company $57,152.

(8) 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 of shares of the Company's
common stock. The Company issued 100,310 shares of the Company's common
stock in 2001 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 amortized 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, 2001, the
Company had reserved 1,696,755 shares out of the 2,000,000 shares available
for the incentive plan.

F-14

In 2001 the Company granted 206,417 options at fair market value, and there
were no options expired or surrendered. The options issued in 2001 will
vest in 2002, 2003, and 2004.

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------
2001 2000 1999
----------------------- -------------------- -------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Options Price Options Price Options Price
--------- -------- --------- -------- ------- --------

Options outstanding,
beginning of period 1,090,217 $ 1.632 741,846 $ 2.045 519,000 $ 2.534
Expired -- $ -- -- $ -- (20,000) 3.290
Surrendered -- $ -- (17,873) $ 3.269 (14,611) $ 2.639
Granted 206,417 $ .643 366,244 $ 1.108 257,457 $ 1.155
Exercised -- $ -- -- -- -- $ --
--------- --------- -------
Options outstanding,
end of period 1,296,634 $ 1.475 1,090,217 $ 1.632 741,846 $ 2.045
========= ========= =======
Options exercisable,
end of period 1,090,217 $ 1.632 1,036,710 $ 1.575 638,846 $ 1.693
========= ========= =======
</Table>

The following summarizes information about stock options outstanding at
December 31, 2001:

<Table>
<Caption>
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
-------------- ----------- ----------- -------- ----------- ---------

$0.63 - $0.99 258,176 8.29 $ 0.67 51,759 $ 0.78
$1.00 - $1.49 667,291 5.21 $ 1.18 667,291 $ 1.18
$1.50 - $1.99 151,500 3.32 $ 1.55 151,500 $ 1.55
$2.00 - $2.99 32,000 5.71 $ 2.08 32,000 $ 2.08
$3.00 - $3.71 187,667 3.68 $ 3.47 187,667 $ 3.47
</Table>

Warrants outstanding at December 31, 2001 were 50,000 expiring June 1,
2005. They are exercisable at $1.50 each.

F-15

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 loss would have
been increased to the pro forma amounts indicated below:

Net income (loss): 2001 2000
----------- -----------

As reported $(3,050,726) $(1,516,310)
Pro forma (3,061,484) (1,825,946)

Earnings (loss) per share, basic and diluted:
As reported $ (.25) $ (.13)
Pro forma (.25) (.16)
</Table>

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:

<Table>
<Caption>
2001 2000
---- ----

Expected option life (years) 5-10 3-9
Risk-free interest rate 4.73% 5.17%
Volatility 76.49% 71.05%
Dividend yield None None
</Table>

(9) 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 $2,700, $4,585, and $4,613 for
2001, 2000, and 1999, respectively.

(10) 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, 2001:

<Table>
<Caption>
YEARS ENDING DECEMBER 31,

2002 $ 492,636
2003 220,190
2004 208,978
2005 198,385
2006 77,459
----------
Total future minimum lease payments $1,197,648
==========
</Table>

Rental expense under operating leases was $234,996, $289,486, and $278,856
for the years ended December 31, 2001, 2000, and 1999, respectively.
Effective July 1, 2001, the Company entered into a

F-16

noncancelable sublease agreement whereby it has subleased excess office
space to a third party. The sublease expires on December 31, 2002, the same
date the Company's primary lease expires on the same office space. Under
the sublease agreement, for 2002 the Company expects to receive $245,735.

(11) SUPPLEMENTAL OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

(a) Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities

<Table>
<Caption>
2001 2000 1999
---------- ---------- --------

Property acquisition costs:
Proved $ 44,362 $ 57,796 $179,107
Unproved 842,063 4,922 --
Exploration costs 538,007 726,107 584,210
Development costs 3,005,871 1,668,174 421,555
</Table>

(b) Results of Operations for Oil and Gas Producing Properties

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-----------------------------------------------
2001 2000 1999
----------- ----------- -----------

Oil and gas revenues $ 3,302,250 $ 3,718,364 $ 2,183,681
Production expenses (1,487,701) (1,456,334) (1,025,947)
Exploration expenses, including dry holes (1,338,385) (1,159,132) (664,581)
Impairment of oil and gas properties (276,435) -- (544,740)
Depreciation, depletion and amortization (1,019,863) (694,743) (663,236)
----------- ----------- -----------
Operating gain (loss) (820,134) 408,155 (714,823)
Income tax expense -- -- --
----------- ----------- -----------
Results of operations from producing activities $ (820,134) $ 408,155 $ (714,823)
=========== =========== ===========
</Table>

F-17

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.

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------
2001 2000 1999
------------------- ------------------- -------------------
Oil Gas Oil Gas Oil Gas
(mbbl) (mmcf) (mbbl) (mmcf) (mbbl) (mmcf)
------ ------ ------ ------ ------ ------

PROVED RESERVES:
Beginning of the year 980 5,115 1,135 4,333 708 8,869
Revisions of previous
estimates (233) (1,165) (178) 145 291 (1,833)
Extensions, discoveries
and additions -- 18 117 947 222 1,557
Property divestitures -- -- -- -- (2) (3,944)
Production (88) (326) (94) (310) (84) (316)
------ ------ ------ ------ ------ ------
End of year 659 3,642 980 5,115 1,135 4,333
====== ====== ====== ====== ====== ======
PROVED DEVELOPED
RESERVES:
Beginning of the year 578 2,484 762 2,151 468 6,174
====== ====== ====== ====== ====== ======
End of year 425 2,076 578 2,484 762 2,151
====== ====== ====== ====== ====== ======
</Table>

(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, 2001, 2000 and 1999 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 2001
calculations were made utilizing prices for oil and natural gas that
existed at December 31, 2001 of $18.83 per barrel and $2.69 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-18

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
--------------------------------------
2001 2000 1999
-------- -------- --------

Future cash flow $ 22,085 $ 75,493 $ 38,106
Future development costs (4,177) (6,050) (5,065)
Future production costs (8,466) (17,504) (13,159)
-------- -------- --------
Future net cash flows before income taxes 9,442 51,939 19,882
Income taxes * (12,282) *
-------- -------- --------
Future net cash flows after income taxes 9,442 39,657 19,882
10% annual discount (4,346) (16,121) (8,462)
-------- -------- --------
Standardized measure of discounted future net
cash flows after income tax $ 5,096 $ 23,536 $ 11,420
======== ======== ========
</Table>

(*) 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

<Table>
<Caption>
YEARS ENDED DECEMBER 31,
(IN THOUSANDS)
--------------------------------------
2001 2000 1999
-------- -------- --------

Standardized measure of discounted future net cash
flows, beginning of year $ 23,536 $ 11,420 $ 8,138
Revisions of previous quantity estimates (7,521) (3,992) (81)
Net changes in prices and production costs and other (13,126) 18,129 3,391
Changes in estimated future development costs (866) (244) (90)
Development costs incurred during period that reduced
future development costs 2,803 559 113
Sales of reserves in place -- -- (2,752)
Extensions and discoveries 64 6,299 3,100
Sales of oil and gas produced during the period, net
of production costs (2,148) (2,488) (1,213)
Income taxes -- (7,289) --
Accretion of discount 2,354 1,142 814
-------- -------- --------
Standardized measure of discounted future net cash
flows, end of year $ 5,096 $ 23,536 $ 11,420
======== ======== ========
</Table>

F-19

(12) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

Summarized quarterly financial data for 2001 and 2000 (in thousands,
except per share data) are as follows:

<Table>
<Caption>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------- ------- ------- ------- -------

2001
Oil and gas revenues $ 943 787 830 742 3,302
Operating profit (loss) (218) (581) (522) (1,684) (3,005)
Net income (loss) (138) (618) (522) (1,773) (3,051)
Earnings (loss) per share:
Basic (.01) (.05) (.04) (.14) (.25)
Diluted (.01) (.05) (.04) (.14) (.25)

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)
</Table>

The sum of the quarterly earnings per share will not necessarily equal
earnings per share for the entire year.

(13) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

The Company paid $122,421, $428,938, and $392,295, for interest in 2001,
2000, and 1999 , respectively. In 2000, the Company issued 1,142,854 shares
of common stock in exchange for $1,000,000 of its convertible-subordinated
notes.

(14) 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, 2001, the Company had a working capital deficit of $
7,851,000. Additionally, the Company's existing bank loan agreement expires
on June 30, 2002. 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 ability to raise capital, the success of the
development program and its ability to stay in compliance with credit
facility debt covenants.

The accompanying financial statements have been prepared assuming the
Company will continue as a going concern. The Company's recurring losses,
net working capital deficit and net capital deficiency raise substantial
doubt about the ability to continue as a going concern. The financial
statements do not include any adjustments that might result from the
outcome of this uncertainty.

F-20

In light of the Company's current working capital situation, the Company is
discontinuing its drilling and exploration activities, and does not anticipate
making any further capital expenditures, until such time as the Company has
significantly reduced its deficit.

The Company's outstanding bank debt is due June 30, 2002. While the
Company is in discussions with its lender, there is no assurance that the line
of credit will be renewed with either the Company's present lender or an
alternative financial institution. Regardless of whether a refinancing can be
arranged, such refinancing is unlikely to be sufficient to allow the Company to
execute its business plan. Accordingly, to continue operations, such as,
drilling additional development and exploration wells, as well as, acquiring
additional acreage, the Company will have to raise capital and/or liquidate
assets. The Company has engaged a financial advisor to assist it in exploring
all financial alternatives ranging from a recapitalization of the Company to a
merger or sale of the Company or certain of its properties. There can be no
assurances, however, that these events will occur and their timing may be
uncertain.

Notwithstanding the foregoing the Company is continually seeking methods and
alternatives of financing in order to provide it with the capital to refinance
its working capital deficit and to improve its financial position. In addition,
the Company is reviewing its asset base so as to monetize assets that are
underperforming. Further, a portion of the Company's business entails selling
working interest participations in oil and gas projects in order to finance
certain exploration drilling activities.

The Company is negotiating with one of its largest trade creditors to enter into
a promissory note that would replace the Company's current trade indebtedness to
that creditor. This note would be secured by a second lien on the assets
presently pledged to the Company's primary lender. The trade creditor also
requires the personal guaranty of this note by E.L. Ames, Jr., the Company's
Chairman and CEO. Pursuant to the terms of the Company's credit agreement, it
must obtain the consent of its primary lender before completing this
transaction.

F-21

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 28th day of March, 2002.

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.

<Table>
<Caption>
DATE TITLE SIGNATURE

/s/ Eugene L. Ames, Jr.
-----------------------
March 28, 2002 Chairman of the Board of Directors Eugene L. Ames, Jr.
and Chief Executive Officer

/s/ John Y. Ames
-----------------------
March 28, 2002 President, Director and Chief John Y. Ames
Operating Officer

/s/ P. Mark Stark
-----------------------
March 28, 2002 Chief Financial Officer P. Mark Stark
(Principal Financial Officer)

/s/ Terry F. Hardeman
-----------------------
March 28, 2002 Chief Accounting Officer Terry F. Hardeman
(Principal Accounting Officer)

/s/ Martin A. Bell
-----------------------
March 28, 2002 Majority of the Directors of the Martin A. Bell
Registrant (including Eugene L.
Ames, Jr. and John Y. Ames)

/s/ Jere W. McKenny
-----------------------
March 28, 2002 Majority of the Directors of the Jere W. McKenny
Registrant (including Eugene L.
Ames, Jr. and John Y. Ames)

/s/ JAMES W. GORMAN
-----------------------
March 28, 2002 Majority of the Directors of the James W. Gorman
Registrant (including Eugene L.
Ames, Jr. and John Y. Ames)
</Table>

INDEX TO EXHIBITS

<Table>
<Caption>
EXHIBIT
NO. ITEM
- ------- ----

*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)

*+4.3 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)

*+10.2 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 (incorporated by reference
to Exhibit 10.3 to the Company's Annual Report on Form 10-K for the
year ended December 31, 2000)

<Table>
<Caption>
EXHIBIT
NO. ITEM
- ------- ----

10.11 Waiver and Amendment dated as of December 11, 2001, by and between the
Company and Hibernia National Bank (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)
</Table>

- ---------
* Incorporated herein by reference.
+ Management contract or compensatory plan or arrangement.