CALLON PETROLEUM CO - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

COMMISSION FILE NUMBER 001-14039

CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)

DELAWARE 64-0844345
--------------------------------- --------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

200 NORTH CANAL STREET
NATCHEZ, MISSISSIPPI 39120 (601) 442-1601
--------------------------------- ---------------------------
(Address of Principal Executive (Registrant's telephone
Offices)(Zip Code) number including area code)

Securities registered pursuant to Section 12(b) of the Act:

TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------
Convertible Exchangeable Preferred Stock, New York Stock Exchange
Series A, Par Value $.01 Per Share
Common Stock, Par Value $.01 Per Share New York Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
11% Senior Subordinated Notes due 2005 New York Stock Exchange
10.25% Senior Subordinated Notes due 2004 New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X. No .
--- ---

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 Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X .
---- ---

The aggregate market value of the voting and non-voting common equity held by
nonaffiliates of the registrant was approximately $53,216,000 as of June 28,
2002, and $46,702,000 as of March 7, 2003 (based on the last reported sale price
of such stock on the New York Stock Exchange on such dates).

As of March 7, 2003, there were 13,919,457 shares of the Registrant's Common
Stock, par value $.01 per share, outstanding.

Document incorporated by reference: Portions of the definitive Proxy Statement
of Callon Petroleum Company (to be filed no later than 120 days after December
31, 2002) relating to the Annual Meeting of Stockholders to be held on May 2,
2003, which is incorporated into Part III of this Form 10-K.

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PART I.

ITEM 1 AND 2. BUSINESS AND PROPERTIES

OVERVIEW

Callon Petroleum Company has been engaged in the exploration, development,
acquisition and production of oil and gas properties since 1950. Our properties
are geographically concentrated primarily offshore in the Gulf of Mexico and
onshore in Louisiana and Alabama. The public Company was incorporated under the
laws of the state of Delaware in 1994 through the consolidation of a publicly
traded limited partnership, a joint venture with a consortium of European
institutional investors and an independent energy company owned by certain
members of current management (the "Consolidation"). As used herein, the
"Company," "Callon," "we," "us," and "our" refer to Callon Petroleum Company and
its predecessors and subsidiaries unless the context requires otherwise.

In 1989, we began increasing our reserves through the acquisition of producing
properties that were geologically complex, had (or were analogous to fields
with) an established production history from stacked pay zones and were
candidates for exploitation. We focused on reducing operating costs and
implementing production enhancements through the application of technologically
advanced production and recompletion techniques.

Over the past seven years, we have also placed emphasis on the acquisition of
acreage with exploration and development drilling opportunities in the Gulf of
Mexico Shelf area. We acquired an infrastructure of production platforms,
gathering systems and pipelines to minimize development expenditures of these
drilling opportunities. We also joined with other industry partners, primarily
Murphy Exploration and Production, Inc., ("Murphy"), to explore federal offshore
blocks acquired in the Gulf of Mexico. Our areas of exploration include the Gulf
of Mexico Deepwater area (generally 900 to 5,500 feet of water).

We ended the year 2002 with estimated net proved reserves of 236 billion cubic
feet of natural gas equivalent ("Bcfe"). This represents a decrease of 22% from
2001 year-end estimated net proved reserves of 303 Bcfe.

The major focus of our future operations is expected to continue to be the
exploration for and development of oil and gas properties, primarily in the Gulf
of Mexico.

AVAILABILITY OF REPORTS

All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and amendments to such reports as well as other filings we
make pursuant to Section 13(a) and 15(d) of the Securities Exchange Act of 1934
are available free of charge on our Internet website. The address of our
Internet website is www.callon.com. Our SEC filings are available on our website
as soon as they are posted to the EDGAR database on the SEC's website.

BUSINESS STRATEGY

Our goal is to increase shareholder value by increasing our reserves,
production, cash flow and earnings. We seek to achieve these goals through the
following strategies:

o Focus on Gulf of Mexico exploration with a balance between shelf and
deepwater areas using the latest available technology.

o Aggressively explore our existing prospect inventory.

o Replenish our prospect inventory with increasing emphasis on prospect
generation.

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o Achieve moderate increases in current production levels through
continued shelf exploration.

o Achieve significant increases in longer-term production levels through
development of deepwater discoveries and ongoing deepwater exploration.

EXPLORATION AND DEVELOPMENT ACTIVITIES

Capital expenditures for exploration and development costs related to oil and
gas properties totaled approximately $61.9 million in 2002. We incurred
approximately $24.4 million in the Gulf of Mexico Shelf area, with approximately
$9.7 million related to the Mobile 952/953/955 acceleration project. The Gulf of
Mexico Deepwater area expenditures ($24.6 million) accounted for the remainder
of the total capital expended, along with $660,000 incurred in leasehold and
seismic acquisition costs and $15.2 million of interest and general and
administrative costs allocable directly to exploration and development projects.
The Gulf of Mexico Deepwater area expenditures were incurred primarily in the
production facility fabrication for our Medusa discovery.

As a result of drilling successes in the Gulf of Mexico Deepwater area, we are
faced with increased costs to develop these significant proved undeveloped
reserves. A large portion of these future development costs will be incurred in
2003 and beyond. While management believes that current availability under our
existing credit facilities along with current cash flows are expected to meet
the needs of these development costs, no assurances can be made that we will be
able to fund these development costs.

SEC REVIEW OF PROVED RESERVES

In October 2002, we received a letter from the SEC requesting supplemental
information concerning our operations in the Gulf of Mexico. We believe that a
similar letter was sent to other oil and gas companies with off-shore
operations. We responded to the SEC's letter on October 18, 2002.

On February 21, 2003, we received another letter from the SEC requesting
additional information about the procedures we used to classify our offshore
reserves as "proved" in our Form 10-K for our fiscal year ended December 31,
2001. The letter also questions the procedures used to classify reserves at our
Boomslang property as proved undeveloped reserves at year end 1998. In 2002, we
drilled a development well which caused us to reduce our estimated reservoir
volumes at our Boomslang property (and record a downward revision of our
estimates of the reserves attributable to such property at December 31, 2002) to
such an extent that the partners determined that the risk of further development
was not economic. The staff of the SEC has asked Callon to restate its financial
statements for fiscal years 2000 and 2001 to remove the reserves attributable to
Boomslang as proved. We responded to the SEC's second letter on March 13, 2003.

We have reviewed the SEC comments with our independent petroleum reserve
engineers, Huddleston & Co., Inc., Houston, Texas. Both Huddleston & Co. and
Callon believe that our proved reserves were properly classified in accordance
with SEC definitions and industry practices. The Company believes the reserve
revision has no effect on prior year financial statements as it represents a
change in estimate. If the SEC requires us to retroactively classify Boomslang
as an unproved property through December, 2002, we would be required to restate
our financial position, results of operations, and supplemental oil and gas
reserve data from 1998 through 2002.

Based on our discussions with others in the oil and gas business, we believe
that the SEC is reviewing generally the procedures used by reserve engineers to
classify oil and gas reserves as proved in the

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deepwater areas of the Gulf of Mexico. In particular, the SEC appears to
indicate that it is not appropriate to classify reserves as proved without
conducting a "flow test." It has not been our practice to conduct a flow test on
our deepwater properties prior to classifying the reserves as proved. We
believe, and have been advised by Huddleston & Co., that our procedures for
classifying our deepwater reserves as proved are in accordance with SEC rules
and industry practices.

The SEC has asked us, and we have provided substantial detail, about our proved
reserves, including the detailed reserve report. At this point, we cannot
predict the ultimate outcome of the SEC's review of our proved reserves. With
respect to our deepwater projects other than Boomslang, we believe that the
outcome of the SEC's review of practices in the oil and gas industry for
classifying deepwater reserves as proved should not affect us materially
differently than other similarly situated oil and gas companies with deepwater
projects. With respect to Boomslang, we believe that reserves attributable to
the project were properly classified as proved at year end 1998, 1999, 2000 and
2001, and that no restatement of our financial statements is required as this
revision to our Boomslang reserves in 2002 represented a change in estimates of
our proved reserves. We cannot make any assurances, however, that the SEC will
ultimately agree with this position.

RISK FACTORS

DECREASE IN OIL AND GAS PRICES MAY ADVERSELY AFFECT OUR RESULTS OF OPERATIONS
AND FINANCIAL CONDITION. Our success is highly dependent on prices for oil and
gas, which are extremely volatile. Any substantial or extended decline in the
price of oil or gas would have a material adverse effect on us. Oil and gas
markets are both seasonal and cyclical. The prices of oil and gas depend on
factors we cannot control such as weather, economic conditions, and levels of
production, actions by OPEC and other countries and government actions. Prices
of oil and gas will affect the following aspects of our business:

o our revenues, cash flows and earnings;

o the amount of oil and gas that we are economically able to produce;

o our ability to attract capital to finance our operations and the cost of
the capital;

o the amount we are allowed to borrow under our senior credit facility;

o the value of our oil and gas properties; and

o the profit or loss we incur in exploring for and developing our
reserves.

UNLESS WE ARE ABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED, OUR CASH FLOWS
AND PRODUCTION WILL DECREASE OVER TIME. Our future success depends upon our
ability to find, develop and acquire oil and gas reserves that are economically
recoverable. As is generally the case for Gulf properties, our producing
properties usually have high initial production rates, followed by a steep
decline in production. As a result, we must continually locate and develop or
acquire new oil and gas reserves to replace those being depleted by production.
We must do this even during periods of low oil and gas prices when it is
difficult to raise the capital necessary to finance these activities and during
periods of high operating costs when it is expensive to contract for drilling
rigs and other equipment and personnel necessary to explore for oil and gas.
Without successful exploration or acquisition activities, our reserves,
production and revenues will decline rapidly. We cannot assure you that we will
be able to find and develop or acquire additional reserves at an acceptable
cost.

A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
IN A SMALL NUMBER OF OFFSHORE PROPERTIES, AND ANY PRODUCTION PROBLEMS OR
INACCURACIES IN RESERVE ESTIMATES RELATED TO THOSE PROPERTIES WOULD ADVERSELY
IMPACT OUR BUSINESS. During 2002, 49% of our daily production came from two of
our properties in the Gulf of Mexico. Moreover, one property accounted for 33%
of our production during this period. If mechanical problems, storms or other
events curtailed a substantial

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portion of this production, our results of operations would be adversely
affected. In addition, at December 31, 2002, most of our proved reserves were
located in five fields in the Gulf of Mexico, with approximately 93% of our
total net proved reserves attributable to these properties. If the actual
reserves associated with any one of these producing properties are less than our
estimated reserves, our results of operations and financial condition could be
adversely affected.

OUR FOCUS ON EXPLORATION PROJECTS INCREASES THE RISKS INHERENT IN OUR OIL AND
GAS ACTIVITIES. Our business strategy focuses on replacing reserves through
exploration, where the risks are greater than in acquisitions and development
drilling. Although we have been successful in exploration in the past, we cannot
assure you that we will continue to increase reserves through exploration or at
an acceptable cost. Additionally, we are often uncertain as to the future costs
and timing of drilling, completing and producing wells. Our drilling operations
may be curtailed, delayed or canceled as a result of a variety of factors,
including:

o unexpected drilling conditions;

o pressure or inequalities in formations;

o equipment failures or accidents;

o adverse weather conditions;

o compliance with governmental requirements; and

o shortages or delays in the availability of drilling rigs and the
delivery of equipment.

BECAUSE WE DO NOT CONTROL, AND DO NOT OPERATE, ALL OF OUR PROPERTIES, ESPECIALLY
OUR DEEPWATER PROPERTIES, WE HAVE LIMITED INFLUENCE OVER THEIR DEVELOPMENT. Our
lack of control could result in the following:

o the operator may initiate exploration or development on a faster or
slower pace than we prefer;

o the operator may propose to drill more wells or build more facilities on
a project than we have funds for or that we deem appropriate, which may
mean that we are unable to participate in the project or share in the
revenues generated by the project even though we paid our share of
exploration costs; and

o if an operator refuses to initiate a project, we may be unable to pursue
the project.

Any of these events could materially reduce the value of our properties.

OUR DEEPWATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
AFFECT THE VALUE OF THOSE ASSETS. Drilling operations in the deepwater area are
by their nature more difficult and costly than drilling operations in shallow
water. Deepwater drilling operations require the application of more advanced
drilling technologies, involving a higher risk of technological failure and
usually have significantly higher drilling costs than shallow water drilling
operations. Deepwater wells are completed using sub sea completion techniques
that require substantial time and the use of advanced remote installation
equipment. These operations involve a high risk of mechanical difficulties and
equipment failures that could result in significant cost overruns.

In deepwater, the time required to commence production following a discovery is
much longer than in shallow water and on-shore. Our deepwater discoveries and
prospects will require the construction of expensive production facilities and
pipelines prior to the beginning of production. We cannot estimate the costs and
timing of the construction of these facilities with certainty, and the accuracy
of our estimates will be affected by a number of factors beyond our control,
including the following:

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o decisions made by the operators of our deepwater wells;

o the availability of materials necessary to construct the facilities;

o the proximity of our discoveries to pipelines; and

o the price of oil and natural gas.

Delays and cost overruns in the commencement of production will affect the value
of our deepwater prospects and the discounted present value of reserves
attributable to those prospects.

Competitive industry conditions may negatively affect our ability to conduct
operations. We operate in the highly competitive areas of oil and gas
exploration, development and production. We compete for the purchase of leases
in the Gulf of Mexico from the U. S. government and from other oil and gas
companies. These leases include exploration prospects as well as properties with
proved reserves. Factors that affect our ability to compete in the marketplace
include:

o our access to the capital necessary to drill wells and acquire
properties;

o our ability to acquire and analyze seismic, geological and other
information relating to a property;

o our ability to retain the personnel necessary to properly evaluate
seismic and other information relating to a property;

o the location of, and our ability to access, platforms, pipelines and
other facilities used to produce and transport oil and gas production;

o the standards we establish for the minimum projected return on an
investment of our capital; and

o the availability of alternate fuel sources.

Our competitors include major integrated oil companies, substantial independent
energy companies, and affiliates of major interstate and intrastate pipelines
and national and local gas gatherers, many of which possess greater financial,
technological and other resources than we do.

OUR COMPETITORS MAY USE SUPERIOR TECHNOLOGY, WHICH WE MAY BE UNABLE TO AFFORD OR
WHICH WOULD REQUIRE COSTLY INVESTMENT BY US IN ORDER TO COMPETE. Our industry is
subject to rapid and significant advancements in technology, including the
introduction of new products and services using new technologies. As our
competitors use or develop new technologies, we may be placed at a competitive
disadvantage, and competitive pressures may force us to implement new
technologies at a substantial cost. In addition, our competitors may have
greater financial, technical and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to implement new
technologies before we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us.
One or more of the technologies that we currently use or that we may implement
in the future may become obsolete, and we may be adversely affected. For
example, marine seismic acquisition technology has been characterized by rapid
technological advancements in recent years, and further significant
technological developments could substantially impair our 3-D seismic data's
value.

WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
UNABLE TO RAISE CAPITAL. WE WILL BE REQUIRED TO MAKE SUBSTANTIAL CAPITAL
EXPENDITURES TO DEVELOP OUR EXISTING RESERVES, AND TO DISCOVER NEW OIL AND GAS
RESERVES. Historically, we have financed these expenditures primarily with cash
from operations, proceeds from bank borrowings and proceeds from the sale of
debt and equity securities. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources" for a discussion of our capital budget. We cannot assure you that we
will be able to raise capital in the future. We also make offers to acquire oil
and gas properties in the ordinary course of our business. If these offers are
accepted, our capital needs may increase substantially.

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We expect to continue using our senior credit facility to borrow funds to
supplement our available cash. The amount we may borrow under our senior credit
facility may not exceed a borrowing base determined by the lenders based on
their projections of our future production, future production costs, taxes,
commodity prices and any other factors deemed relevant by our lenders. We cannot
control the assumptions the lenders use to calculate our borrowing base. The
lenders may, without our consent, adjust the borrowing base semiannually or in
situations where we purchase or sell assets or issue debt securities. If our
borrowings under the senior credit facility exceed the borrowing base, the
lenders may require that we repay the excess. If this were to occur, we might
have to sell assets or seek financing from other sources. Sales of assets could
further reduce the amount of our borrowing base. We cannot assure you that we
would be successful in selling assets or arranging substitute financing. If we
were not able to repay borrowings under our senior credit facility to reduce the
outstanding amount to less than the borrowing base, we would be in default under
our senior credit facility. For a description of our senior credit facility and
its principal terms and conditions, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

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OUR RESERVE INFORMATION REPRESENTS ESTIMATES THAT MAY TURN OUT TO BE INCORRECT
IF THE ASSUMPTIONS UPON WHICH THESE ESTIMATES ARE BASED ARE INACCURATE. ANY
MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES OR UNDERLYING ASSUMPTIONS WILL
MATERIALLY AFFECT THE QUANTITIES AND PRESENT VALUE OF OUR RESERVES. The process
of estimating oil and gas reserves is complex. It requires interpretations of
available technical data and various assumptions, including assumptions relating
to economic factors. Any significant inaccuracies in these interpretations or
assumptions could materially affect the estimated quantities and present value
of reserves shown in this annual report.

In order to prepare these estimates, we must project production rates and the
timing of development expenditures. The assumptions regarding the timing and
costs to commence production from our deepwater wells used in preparing our
reserves are often subject to revisions over time as described under "our
deepwater operations have special operational risks that may negatively affect
the value of those assets." We must also analyze available geological,
geophysical, production and engineering data, the extent, quality and
reliability of which can vary. The process also requires economic assumptions,
such as oil and gas prices, drilling and operating expenses, capital
expenditures, taxes and availability of funds. Therefore, estimates of oil and
gas reserves are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from our estimates. Any significant variance
could materially affect the estimated quantities and present value of reserves
shown in this report. In addition, we may adjust estimates of proved reserves to
reflect production history, results of exploration and development, prevailing
oil and gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net cash flows from our
proved reserves referred to in this report is the current market value of our
estimated oil and gas reserves. In accordance with SEC requirements, we
generally base the estimated discounted future net cash flows from our proved
reserves on prices and costs on the date of the estimate. Actual future prices
and costs may differ materially from those used in the present value estimate.

Information about reserves constitutes forward-looking information. See
"Forward-Looking Statements" for information regarding forward-looking
information. The discounted present value of our oil and gas reserves is
prepared in accordance with guidelines established by the SEC. A purchaser of
reserves would use numerous other factors to value our reserves. The discounted
present value of reserves, therefore, does not represent the fair market value
of those reserves.

On December 31, 2002, approximately 81.4% of the discounted present value of our
estimated net proved reserves were proved undeveloped. Proved undeveloped oil
volumes represented 96% of total proved oil reserves. Substantially all of these
proved undeveloped reserves were attributable to our deepwater properties.
Development of these properties is subject to additional risks as described
above.

THE SEC MAY REQUIRE US TO BOOK RESERVES AS PROVED IN A MANNER THAT DIFFERS FROM
OUR HISTORICAL PRACTICES AND CURRENT INDUSTRY STANDARDS, AND WHICH MAY RESULT IN
A SIGNIFICANT DOWNWARD REVISION OF OUR PROVED RESERVES. As discussed above, in
October 2002 and February 2003, we received letters from the SEC regarding our
Annual Report on Form 10-K for the year ended December 31, 2001 requesting
supplemental information concerning our operations in the Gulf of Mexico. The
comment letters requested information about the procedures we used to classify
our deepwater reserves as proved and requested that our financials be restated
to reflect the removal of the Boomslang reserves as proved for all prior periods
during which such reserves were reported as proved. We have reviewed the SEC

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comments with our independent petroleum reserve engineers, Huddleston & Co.,
Inc. of Houston, Texas. Both Huddleston & Co and Callon believe that such
reserves were properly classified as proved. However, if the SEC decides to
question our other deepwater properties and these reserves are ultimately
required to be reclassified as not proved; our proved reserves will be
materially reduced. If the SEC requires us to retroactively classify Boomslang
as an unproved property through December, 2002, we would be required to restate
our financial position, results of operations, and supplemental oil and gas
reserve data from 1998 through 2002. A material reduction in our proved reserves
could have a material adverse effect on our financial condition and results of
operations.

WEATHER, UNEXPECTED SUBSURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING
HAZARDS MAY ADVERSELY IMPACT OUR ABILITY TO CONDUCT BUSINESS. There are many
operating hazards in exploring for and producing oil and gas, including:

o our drilling operations may encounter unexpected formations or
pressures, which could cause damage to equipment or personal injury;

o we may experience equipment failures which curtail or stop production;
and

o we could experience blowouts or other damages to the productive
formations that may require a well to be re-drilled or other corrective
action to be taken.

In addition, any of the foregoing may result in environmental damages for which
we will be liable. Moreover, a substantial portion of our operations are
offshore and are subject to a variety of risks peculiar to the marine
environment such as capsizing, collisions, hurricanes and other adverse weather
conditions. These conditions can cause substantial damage to facilities and
interrupt production. Offshore operations are also subject to more extensive
governmental regulation.

We cannot assure you that we will be able to maintain adequate insurance at
rates we consider reasonable to cover our possible losses from operating
hazards. The occurrence of a significant event not fully insured or indemnified
against could materially and adversely affect our financial condition and
results of operations.

WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM
PRICE INCREASES. Part of our business strategy is to reduce our exposure to the
volatility of oil and gas prices by hedging a portion of our production. In a
typical hedge transaction, we will have the right to receive from the other
parties to the hedge the excess of the fixed price specified in the hedge over a
floating price based on a market index, multiplied by the quantity hedged. If
the floating price exceeds the fixed price, we are required to pay the other
parties this difference multiplied by the quantity hedged. We are required to
pay the difference between the floating price and the fixed price when the
floating price exceeds the fixed price regardless of whether we have sufficient
production to cover the quantities specified in the hedge. Significant
reductions in production at times when the floating price exceeds the fixed
price could require us to make payments under the hedge agreements even though
such payments are not offset by sales of production. Hedging will also prevent
us from receiving the full advantage of increases in oil or gas prices above the
fixed amount specified in the hedge. See "Quantitative and Qualitative
Disclosures About Market Risks" for a discussion of our hedging practices.

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COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
AND COULD NEGATIVELY IMPACT PRODUCTION. Our operations are subject to numerous
laws and regulations governing the operation and maintenance of our facilities
and discharge of materials into the environment or otherwise relating to
environmental protection. For a discussion of the material regulations
applicable to us, see "Federal Regulations," "State Regulations," and
"Environmental Regulations." These laws and regulations may:

o require that we acquire permits before commencing drilling;

o restrict the substances that can be released into the environment in
connection with drilling and production activities;

o limit or prohibit drilling activities on protected areas such as
wetlands or wilderness areas; and

o require remedial measures to mitigate pollution from former operations,
such as dismantling abandoned production facilities.

Under these laws and regulations, we could be liable for personal injury and
clean-up costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. We maintain limited insurance
coverage for sudden and accidental environmental damages. We do not believe that
insurance coverage for environmental damages that occur over time is available
at a reasonable cost. Also, we do not believe that insurance coverage for the
full potential liability that could be caused by sudden and accidental
environmental damages is available at a reasonable cost. Accordingly, we may be
subject to liability or we may be required to cease production from properties
in the event of environmental damages.

FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION AND OUR
FINANCIAL RESULTS. The ability to market oil and gas from our wells depends upon
numerous factors beyond our control. These factors include:

o the extent of domestic production and imports of oil and gas;

o the proximity of the gas production to gas pipelines;

o the availability of pipeline capacity;

o the demand for oil and gas by utilities and other end users;

o the availability of alternative fuel sources;

o the effects of inclement weather;

o state and federal regulation of oil and gas marketing; and

o federal regulation of gas sold or transported in interstate commerce.

Because of these factors, we may be unable to market all of the oil or gas we
produce. In addition, we may be unable to obtain favorable prices for the oil
and gas we produce.

IF OIL AND GAS PRICES DECREASE, WE MAY BE REQUIRED TO TAKE WRITEDOWNS. We may be
required to writedown the carrying value of our oil and gas properties when oil
and gas prices are low or if we have substantial downward adjustments to our
estimated net proved reserves, increases in our estimates of development costs
or deterioration in our exploration results. Under the full cost method which we
use to account for our oil and gas properties, the net capitalized costs of our
oil and gas properties may not exceed the present value, discounted at 10%, of
future net cash flows from estimated net proved reserves, using period end oil
and gas prices or prices as of the date of our auditor's report, plus the lower
of cost or fair market value of our unproved properties. If net capitalized
costs of our oil and gas properties exceed this limit, we must charge the amount
of the excess to earnings. This type of charge will not affect our cash flows,
but will reduce the book value of our stockholders' equity. We review the
carrying value of our properties quarterly, based on prices in effect as of the
end of each quarter or at the time of reporting our

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results. Once incurred, a writedown of oil and gas properties is not reversible
at a later date, even if prices increase.

FORWARD-LOOKING STATEMENTS

In this report, we have made many forward-looking statements. We cannot assure
you that the plans, intentions or expectations upon which our forward-looking
statements are based will occur. Our forward-looking statements are subject to
risks, uncertainties and assumptions, including those discussed elsewhere in
this report. Forward-looking statements include statements regarding:

o our oil and gas reserve quantities, and the discounted present value of
these reserves;

o the amount and nature of our capital expenditures;

o drilling of wells;

o the timing and amount of future production and operating costs;

o business strategies and plans of management; and

o prospect development and property acquisitions.

Some of the risks, which could affect our future results and could cause results
to differ materially from those expressed in our forward-looking statements
include:

o general economic conditions;

o the volatility of oil and natural gas prices;

o the uncertainty of estimates of oil and natural gas reserves;

o the impact of competition;

o the availability and cost of seismic, drilling and other equipment;

o operating hazards inherent in the exploration for and production of
oil and natural gas;

o difficulties encountered during the exploration for and production
of oil and natural gas;

o difficulties encountered in delivering oil and natural gas to
commercial markets;

o changes in customer demand and producers' supply;

o the uncertainty of our ability to attract capital;

o compliance with, or the effect of changes in, the extensive
governmental regulations regarding the oil and natural gas business;

o actions of operators of our oil and gas properties; and

o weather conditions.

The information contained in this report, including the information set forth
under the heading "Risk Factors," identifies additional factors that could
affect our operating results and performance. We urge you to carefully consider
these factors and the other cautionary statements in this report. Our
forward-looking statements speak only as of the date made, and we have no
obligation to update these forward-looking statements.

CORPORATE OFFICES

Our headquarters are located in Natchez, Mississippi, in approximately 51,500
square feet of owned space, with a field office in Houston, Texas. We also
maintain owned or leased field offices in the area of the major fields in which
we operate properties or have a significant interest. Replacement of any of our
leased offices would not result in material expenditures by us as alternative
locations to our leased space are anticipated to be readily available.

11

EMPLOYEES

We had 100 employees as of December 31, 2002, none of whom are currently
represented by a union. We believe that we have good relations with our
employees. We employ nine petroleum engineers and seven petroleum geoscientists.

FEDERAL REGULATIONS

SALES OF NATURAL GAS. Effective January 1, 1993, the Natural Gas Wellhead
Decontrol Act deregulated prices for all "first sales" of natural gas. Thus, all
sales of gas by the Company may be made at market prices, subject to applicable
contract provisions.

TRANSPORTATION OF NATURAL GAS. The rates, terms and conditions applicable to the
interstate transportation of natural gas by pipelines are regulated by the
Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"),
as well as under section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985,
the FERC has implemented regulations intended to make natural gas transportation
more accessible to gas buyers and sellers on an open-access, non-discriminatory
basis.

The FERC has announced several important transportation-related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000 concerning alternatives to its traditional
cost-of-service rate-making methodology to establish the rates interstate
pipelines may charge for their services. The final rule revises FERC's pricing
policy and current regulatory framework to improve the efficiency of the market
and further enhance competition in natural gas markets.

With respect to the transportation of natural gas on or across the Outer
Continental Shelf ("OCS"), the FERC requires, as part of its regulation under
the Outer Continental Shelf Lands Act, that all pipelines provide open and
non-discriminatory access to both owner and non-owner shippers. Although to date
the FERC has imposed light-handed regulation on off-shore facilities that meet
its traditional test of gathering status, it has the authority to exercise
jurisdiction under the Outer Continental Shelf Lands Act ("OCSLA") over
gathering facilities, if necessary, to permit non-discriminatory access to
service. For those facilities transporting natural gas across the OCS that are
not considered to be gathering facilities, the rates, terms, and conditions
applicable to this transportation are regulated by FERC under the NGA and NGPA,
as well as the OCSLA.

SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil and condensate can be
made by the Company at market prices not subject at this time to price controls.
The price that the Company receives from the sale of these products will be
affected by the cost of transporting the products to market. The rates, terms,
and conditions applicable to the interstate transportation of oil and related
products by pipelines are regulated by the FERC under the Interstate Commerce
Act. As required by the Energy Policy Act of 1992, the FERC has revised its
regulations governing the rates that may be charged by oil pipelines. The new
rules, which were effective January 1, 1995, provide a simplified, generally
applicable method of regulating such rates by use of an index for setting rate
ceilings. The FERC will also, under defined circumstances, permit alternative
ratemaking methodologies for interstate oil pipelines such as the use of cost of
service rates, settlement rates, and market-based rates. Market-based rates will
be permitted to the extent the pipeline can demonstrate that it lacks
significant market power in the market in which it proposes to charge
market-based rates. The cumulative effect that these rules may have on moving
the Company's production to market cannot yet be determined.

With respect to the transportation of oil and condensate on or across the OCS,
the FERC requires, as part of its regulation under the OCSLA, that all pipelines
provide open and non-discriminatory access to both owner and non-owner shippers.
Accordingly, the FERC has the authority to exercise jurisdiction under the
OCSLA, if necessary, to permit non-discriminatory access to service.

12

LEGISLATIVE PROPOSALS. In the past, Congress has been very active in the area of
natural gas regulation. There are legislative proposals pending in Congress and
in various state legislatures which, if enacted, could significantly affect the
petroleum industry. At the present time it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on the Company's
operations.

FEDERAL, STATE OR INDIAN LEASES. In the event the Company conducts operations on
federal, state or Indian oil and gas leases, such operations must comply with
numerous regulatory restrictions, including various nondiscrimination statutes,
royalty and related valuation requirements, and certain of such operations must
be conducted pursuant to certain on-site security regulations and other
appropriate permits issued by the Bureau of Land Management ("BLM") or Minerals
Management Service ("MMS") or other appropriate federal or state agencies.

The Company's OCS leases in federal waters are administered by the MMS and
require compliance with detailed MMS regulations and orders. The MMS has
promulgated regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. Under
certain circumstances, the MMS may require Company operations on federal leases
to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition and
operations. On March 15, 2000, the MMS issued a final rule effective June 1,
2000 which amends its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. Among other matters, this
rule amends the valuation procedure for the sale of federal royalty oil by
eliminating posted prices as a measure of value and relying instead on arm's
length sales prices and spot market prices as market value indicators. Because
the Company sells its production in the spot market and therefore pays royalties
on production from federal leases, it is not anticipated that this final rule
will have any substantial impact on the Company.

The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
ownership of any interest in federal onshore oil and gas leases by a foreign
citizen of a country that denies "similar or like privileges" to citizens of the
United States. Such restrictions on citizens of a "non-reciprocal" country
include ownership or holding or controlling stock in a corporation that holds a
federal onshore oil and gas lease. If this restriction is violated, the
corporation's lease can be canceled in a proceeding instituted by the United
States Attorney General. Although the regulations of the BLM (which administers
the Mineral Act) provide for agency designations of non-reciprocal countries,
there are presently no such designations in effect. The Company owns interests
in numerous federal onshore oil and gas leases. It is possible that holders of
equity interests in the Company may be citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the
Mineral Act.

STATE REGULATIONS

Most states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. The rate of production may be regulated and the maximum daily
production allowable from both oil and gas wells may be established on a market
demand or conservation basis or both.

The Company may enter into agreements relating to the construction or operation
of a pipeline system for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such
operations may, in certain instances, be subject to the jurisdiction of such
state's administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates which the Company could charge
for gas, the transportation of gas, and the costs of construction and operation
of such

13

pipeline would be impacted by the rules and regulations governing such matters,
if any, of such administrative authority. Further, such a pipeline system would
be subject to various state and/or federal pipeline safety regulations and
requirements, including those of, among others, the Department of
Transportation. Such regulations can increase the cost of planning, designing,
installing and operating such facilities. The impact of such pipeline safety
regulations would not be any more adverse to the Company than it would be to
other similar owners or operators of such pipeline facilities.

ENVIRONMENTAL REGULATIONS

GENERAL. The Company's activities are subject to federal, state and local laws
and regulations governing environmental quality and pollution control. Although
no assurances can be made, the Company believes that, absent the occurrence of
an extraordinary event, compliance with existing federal, state and local laws,
rules and regulations regulating the release of materials into the environment
or otherwise relating to the protection of the environment will not have a
material effect upon the capital expenditures, earnings or the competitive
position of the Company with respect to its existing assets and operations. The
Company cannot predict what effect future regulation or legislation, enforcement
policies, and claims for damages to property, employees, other persons and the
environment resulting from the Company's operations could have on its
activities.

Activities of the Company with respect to natural gas facilities, including the
operation and construction of pipelines, plants and other facilities for
transporting, processing, treating or storing natural gas and other products,
are subject to stringent environmental regulation by state and federal
authorities including the United States Environmental Protection Agency ("EPA").
Such regulation can increase the cost of planning, designing, installing and
operating such facilities. In most instances, the regulatory requirements relate
to water and air pollution control measures. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on it, risks of substantial costs and liabilities are inherent in oil and
gas production operations, and there can be no assurance that significant costs
and liabilities will not be incurred. Moreover, it is possible that other
developments, such as stricter environmental laws and regulations, and claims
for damages to property or persons resulting from oil and gas production, would
result in substantial costs and liabilities to the Company.

SOLID AND HAZARDOUS WASTE. The Company currently owns or leases, and in the past
owned or leased, properties that have been used for the exploration and
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other solid wastes may have been disposed or released on or
under the properties owned or leased by the Company or on or under locations
where such wastes have been taken for disposal. In addition, many of these
properties have been operated by third parties. The Company has no control over
such entities' treatment of hydrocarbons or other solid wastes and the manner in
which such substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under new laws, the Company could be required to remediate property,
including groundwater, containing or impacted by previously disposed wastes
(including wastes disposed or released by prior owners or operators, or property
contamination, including groundwater contamination by prior owners or operators)
or to perform remedial plugging operations to prevent future or mitigate
existing contamination.

The Company generates wastes, including hazardous wastes that are subject to the
federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The Environmental Protection Agency ("EPA") and various state agencies
have limited the disposal options for certain wastes, including wastes
designated as hazardous under the RCRA and similar state statutes ("Hazardous
Wastes"). Furthermore, it is possible that certain wastes generated by the
Company's oil and gas operations that are (currently exempt from

14

treatment as) Hazardous Wastes may in the future be designated as Hazardous
Wastes under RCRA or other applicable statutes and, therefore, may be subject to
more rigorous and costly disposal requirements.

SUPERFUND. The federal Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, generally imposes
joint and several liability for costs of investigation and remediation and for
natural resource damages, without regard to fault or the legality of the
original conduct, on certain classes of persons with respect to the release into
the environment of substances designated under CERCLA as hazardous substances
("Hazardous Substances"). These classes of persons, or so-called potentially
responsible parties ("PRPs"), include the current and certain past owners and
operators of a facility where there has been a release or threat of release of a
Hazardous Substance and persons who disposed of or arranged for the disposal of
Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in
some cases, third parties to take actions in response to threats to the public
health or the environment and to seek to recover from the PRPs the costs of such
action. Although CERCLA generally exempts "petroleum" from the definition of
Hazardous Substance, in the course of its operations, the Company has generated
and will generate wastes that may fall within CERCLA's definition of Hazardous
Substance. The Company may also be the owner or operator of sites on which
Hazardous Substances have been released. To its knowledge, neither the Company
nor its predecessors have been designated as a PRP by the EPA under CERCLA; the
Company also does not know of any prior owners or operators of its properties
that are named as PRPs related to their ownership or operation of such
properties.

CLEAN WATER ACT. The Clean Water Act ("CWA") imposes restrictions and strict
controls regarding the discharge of wastes including produced waters and other
oil and natural gas wastes, into waters of the United States, a term broadly
defined. These controls have become more stringent over the years, and it is
probable that additional restrictions will be imposed in the future. Permits
must be obtained to discharge pollutants into federal waters. The CWA provides
for civil, criminal and administrative penalties for unauthorized discharges of
oil and hazardous substances and of other pollutants. It imposes substantial
potential liability for the costs of removal or remediation associated with
discharges of oil or hazardous substances and other pollutants. State laws
governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or its derivatives, or other hazardous substances, into state waters.
In addition, the EPA has promulgated regulations that may require us to obtain
permits to discharge storm water runoff, including discharges associated with
construction activities. In the event of an unauthorized discharge of wastes,
the Company may be liable for penalties and costs.

OIL POLLUTION ACT. The Oil Pollution Act of 1990 ("OPA"), which amends and
augments oil spill provisions of CWA, imposes certain duties and liabilities on
certain "responsible parties" related to the prevention of oil spills and
damages resulting from such spills in or threatening United States waters or
adjoining shorelines. A liable "responsible party" includes the owner or
operator of a facility, vessel or pipeline that is a source of an oil discharge
or that poses the substantial threat of discharge, or the lessee or permittee of
the area in which a discharging facility is located. OPA assigns joint and
several liability, without regard to fault, to each liable party for oil removal
costs and a variety of public and private damages. Although defenses and
limitations exist to the liability imposed by OPA, they are limited. In the
event of an oil discharge or substantial threat of discharge, the Company may be
liable for costs and damages.

The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain amendments to the OPA that were enacted in 1996 require owners
and operators of offshore facilities that have a worst case oil spill potential
of more than 1,000 barrels to demonstrate financial responsibility in amounts
ranging from $10 million in specified state waters and $35 million in federal
outer continental shelf ("OCS") waters, with higher amounts, up to $150 million
based upon worst

15

case oil-spill discharge volume calculations. The Company believes that it has
established adequate proof of financial responsibility for its offshore
facilities.

AIR EMISSIONS. The Company's operations are subject to local, state and federal
regulations for the control of emissions from sources of air pollution. Federal
and state laws require new and modified sources of air pollutants to obtain
permits prior to commencing construction. Major sources of air pollutants are
subject to more stringent, federally imposed requirements including additional
permits. Federal and state laws designed to control hazardous (toxic) air
pollutants, might require installation of additional controls. Administrative
enforcement actions for failure to comply strictly with air pollution
regulations or permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could bring lawsuits for civil penalties or require the Company to forego
construction, modification or operation of certain air emission sources.

COASTAL COORDINATION. There are various federal and state programs that regulate
the conservation and development of coastal resources. The federal Coastal Zone
Management Act ("CZMA") was passed in 1972 to preserve and, where possible,
restore the natural resources of the Nation's coastal zone. The CZMA provides
for federal grants for state management PROGRAMS that regulate land use, water
use and coastal development.

Various states, such as Alabama, Louisiana and Texas, also have coastal
management programs, which provide for, among other things, the coordination
among local and state authorities to protect coastal resources through
regulating land use, water, and coastal development. Coastal management programs
also may provide for the review of state and federal agency rules and agency
actions for consistency with the goals and policies of the state coastal
management plan. This review may impact agency permitting and review activities
and add an additional layer of review to certain activities undertaken by the
Company.

OSHA AND OTHER REGULATIONS. The Company is subject to the requirements of the
federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The OSHA hazard communication standard, the EPA community
right-to-know regulations under Title III of CERCLA and similar state statutes
require the Company to organize and/or disclose information about hazardous
materials used or produced in its operations.

Management believes that the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements would not have a material adverse impact on the Company.

PROPERTY SUMMARY

We are engaged in the exploration, development, acquisition and production of
oil and gas properties and natural gas transmission and provide oil and gas
property management services for other investors. Our properties are
concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana
and Alabama. We have historically grown our reserves and production by focusing
primarily on low to moderate risk exploration and acquisition opportunities in
the Gulf of Mexico Shelf area. Over the last several years, we have expanded our
area of exploration to include the Gulf of Mexico Deepwater area. As of December
31, 2002, our estimated net proved reserves totaled 24.0 million barrels of oil
("MBbl") and 91.5 billion cubic feet of natural gas ("Bcf"), with a pre-tax
present value, discounted at 10%, of the estimated future net revenues based on
constant prices in effect at year-end ("Discounted Cash Flow") of $623.9
million. Gas constitutes approximately 39% of our total estimated proved
reserves and approximately 17% of our total estimated proved reserves are proved
producing reserves.

16

Our Medusa (Mississippi Canyon Blocks 538/582) discovery and Habanero (Garden
Banks Block 341) discovery are projected to begin production late in the third
quarter of 2003. Construction of a production facility, subsea completions and
flowlines are projected to be completed by the fall of 2003. These two deepwater
discoveries are expected to increase our projected production from our existing
producing properties by 58% in the second half of 2003. A detail discussion of
each of these properties is provided in the Significant Properties section of
this report.

SIGNIFICANT PROPERTIES

The following table shows discounted cash flows and estimated net proved oil and
gas reserves by major field, within the focus area, for our seven largest fields
and for all other properties combined at December 31, 2002.

17

GULF OF MEXICO SHELF:
Mobile Blocks 863/864/907/908 Callon -- 9,991 9,991 27,866
Mobile Blocks 952/953/955 Callon -- 23,117 23,117 76,382
Ship Shoal Blocks 28/35 Callon 12 1,141 1,210 3,722

ONSHORE AND OTHER:
Big Escambia Creek Exxon 353 1,298 3,414 8,199
Other Various 691 7,126 11,274 13,106
------------ ------------ ------------ ------------

TOTAL NET PROVED RESERVES 24,043 91,539 235,799 $ 623,946
============ ============ ============ ============

(a) Represents the present value of future net cash flows before deduction
of federal income taxes, discounted at 10%, attributable to estimated
net proved reserves as of December 31, 2002, as set forth in the
Company's reserve reports prepared by its independent petroleum reserve
engineers, Huddleston & Co., Inc. of Houston, Texas.

GULF OF MEXICO DEEPWATER

Medusa, Mississippi Canyon Blocks 538/582

Medusa was our third deepwater discovery and was announced in September 1999. We
drilled the initial test well in 2,235 feet of water to a total depth of 16,241
feet and encountered over 120 feet of pay in two intervals. We performed
subsequent sidetrack drilling from the well bore to determine the extent of the
discovery. We drilled a second successful well in the first quarter of 2000 to
further delineate the extent of the pay intervals. We own a 15% working
interest, Murphy, the operator, owns a 60% interest and Agip Ventures, formerly
British-Borneo Petroleum, Inc., owns the remaining 25% interest.

In 2001 a drilling program began which included four development wells and one
sidetrack. The program included production casing being set on six wells which
will provide initial production take-points. The program was completed in the
first half of 2002. Also in 2001, the operator submitted an Authorization

18

for Expenditure for a floating production system at Medusa and awarded the
contract to J. Ray McDermott, Inc. The spar was barged to the Mississippi Canyon
Block 582 in January 2003 and installed. The topside deck and production
facilities should be delivered and lifted into place atop the spar during the
second quarter of 2003. Initial production is scheduled to commence in the third
quarter of 2003 as the six wells are individually completed and tied into the
spar and production facilities. Once all six wells are tied in, it is estimated
that the production facility will have the capacity to handle up to 40,000
barrels of crude oil and 110 million cubic feet of natural gas per day.

Habanero, Garden Banks Block 341

During February 1999 the initial test well on our Habanero prospect encountered
over 200 feet of net pay in two zones. Located in 2,000 feet of water, the well
was drilled to a measured depth of 21,158 feet. This discovery was our second
deepwater success. We own an 11.25% working interest in the well. It is operated
by Shell Deepwater Development Inc., which owns a 55% working interest, with the
remaining working interest being owned by Murphy.

Current development plans include sub-sea completion and tie back to an existing
production facility in the area that is operated by Shell. A field delineation
program began in mid-year 2001, which included sidetracking the discovery well
with three sidetracks. Production casing was set on this well through one of the
sidetracks to the Hab 52 oil sand and the Hab 55 gas sand. Initial production
will be from the Hab55 gas sand and future recompletions are scheduled up-hole
to the Hab 52 oil sand for this well. Also, a development well is scheduled to
be drilled in the summer of 2003 and will provide a take-point for production
from the Hab 52 oil sand. The operator has submitted to the co-owners a
development schedule which estimates initial production to commence in late
summer 2003.

Entrada, Garden Banks Blocks 738/782/826/827

The Entrada discovery is located in approximately 4,500 feet of water in the
Gulf of Mexico. Two wells and seven sidetracks have been drilled to date on
Garden Banks 782 on a northwest plunging salt ridge along the southern edge of
the Entrada Basin. Multiple stacked amplitudes trapped against a salt or fault
interface characterize the Entrada Area. We own a 20% working interest in this
discovery with BP Amoco, the operator, holding the remaining working interest.

The owners of an adjacent discovery have announced their plans to construct
production facilities to enable them to be a regional off-take point in
Southeastern Garden Banks. These plans include handling third party tie-ins,
which we expect to include Entrada. First production from their discovery is
expected in late 2004. Information obtained in a data swap with the adjacent
owners, is being incorporated into the Entrada development plans. An integrated
project team was formed by the working interest owners during 2002 to begin
planning the development of the field.

Boomslang, Ewing Bank Block 994

A major revision to reserves in 2002 was at our Boomslang discovery. The initial
exploratory well drilled at this location in 1998 encountered 185 feet of pay.
The first well was drilled with significant mechanical problems and was
subsequently determined not to be a viable well for completion and production of
the estimated proved reserves encountered in this initial well. A second well,
to serve as a production take point, was drilled in the fourth quarter of 2002
in a down dip direction from the first well targeting what was anticipated to be
a better sand development in the three separate reservoirs found in the first
well, but still up dip of the lowest known hydrocarbons in the first well.
Reservoir sand quality changed dramatically, reducing the estimated reservoir
volumes found and booked as estimated proved reserves by the first well

19

to an extent that the partners determined that the risk of development was not
economic. Callon had a 40% working interest. The Company's proved reserves in
the prior year included 7.2 million barrels of oil and 13 billion cubic feet of
natural gas attributable to Boomslang.

GULF OF MEXICO SHELF

Mobile Blocks 863/864/ 907/908

We own an average 67.9% working interest in these blocks and we are the
operator. The Mobile 864 unit, in which we have a 66.4% working interest, has
three producing wells, unit production facilities and covers portions of these
four blocks. In addition, there are two other wells located on the blocks in
which we own a 100% and 66.4% working interest. These wells produce through the
unit facilities. During 2002 the unit and the other two wells produced an
average of 7.1 MMcf per day net to us.

Mobile Blocks 952/953/955

We own a 100% working interest in these three blocks and we are the operator. In
the fourth quarter of 2001, we initiated a production acceleration program for
Mobile Blocks 952, 953 and 955, which were being produced through the Mobile
Block 864 unit facilities. Plans included an acceleration well, which was
successfully drilled in the fourth quarter of 2001. Stand-alone production
facilities were installed and production flow lines were rerouted to the new
facilities. Production commenced through the new facilities in April 2002. This
program offset normal production declines curves from existing field wells and
added an annual increase of 3.8 MMcf per day net to us over 2001 production
levels of 10.1 MMcf per day. From May 1, 2002 to December 31, 2002 the wells
produced 18.6 MMcf per day net to us.

Ship Shoal Blocks 28/35

We successfully drilled an exploratory well on our prospect at Ship Shoal Blocks
28 and 35 during the third quarter of 2002. The well was drilled to a measured
depth of 15,237 feet (12,295 feet of true vertical depth) and encountered 140
feet of net natural gas pay. The well is being completed as a single producer in
the deepest of three productive intervals and is scheduled for first production
during the second quarter of 2003. We operate and own a 22% working interest.

ONSHORE AND OTHER

Big Escambia Creek

This gas field in south Alabama produces from the Smackover formation at depths
ranging from 15,100 to 15,600 and is operated by Exxon/Mobil. We own an average
working interest of 4.9% (5.5% net revenue interest), in six wells and a 2.2%
average royalty interest in another five wells. This field produced 1.0 MMcfe
per day to our interest in 2002. The field has an estimated reserve life in
excess of ten years given current production rates.

Other

20

We own various royalty and working interest in numerous onshore areas and the
Gulf of Mexico other than the fields discussed above.

OIL AND GAS RESERVES

The following table sets forth certain information about our estimated proved
reserves as of the dates set forth below.

(a) The estimates include reserve volumes of approximately 3.5 Bcf, $31.8
million of pre-tax future net cash flows and $29.5 million of pre-tax discounted
present value in 2000, 1.2 Bcf, $2.9 million of pre-tax discounted present value
in 2001, attributable to a volumetric production payment. Standardized measure
of discounted future net cash flows does not include any volumes or cash flows
associated with the volumetric production payment.

Our independent reserve engineers, Huddleston & Co., Inc. prepared the estimates
of the proved reserves and the future net cash flows and present value thereof
attributable to such proved reserves. Reserves were estimated using oil and gas
prices and production and development costs in effect on December 31 of each
such year, without escalation, and were otherwise prepared in accordance with
Securities and Exchange Commission regulations regarding disclosure of oil and
gas reserve information.

There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond our control or the control of the
reserve engineers. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner. The accuracy of any reserve or cash flow estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Estimates by different engineers often vary, sometimes significantly.
In addition, physical factors, such as the results of drilling, testing and
production subsequent to the date of an

21

estimate, as well as economic factors, such as an increase or decrease in
product prices that renders production of such reserves more or less economic,
may justify revision of such estimates. Accordingly, reserve estimates could be
different from the quantities of oil and gas that are ultimately recovered.

We have not filed any reports with other federal agencies which contain an
estimate of total proved net oil and gas reserves during our last fiscal year.

PRESENT ACTIVITIES AND PRODUCTIVE WELLS

The following table sets forth the wells we have drilled and completed during
the periods indicated. All such wells were drilled in the continental United
States primarily in federal and state waters in the Gulf of Mexico.

The following table sets forth our productive wells as of December 31, 2002:

A well is categorized as an oil well or a natural gas well based upon the ratio
of oil to gas reserves on a Mcfe basis. However, some of our wells produce both
oil and gas. At December 31, 2002, we had no wells with multiple completions. At
December 31, 2002, we had 1 gross (1.0 net) exploratory gas well in progress.

22

LEASEHOLD ACREAGE

The following table shows our approximate developed and undeveloped (gross and
net) leasehold acreage as of December 31, 2002.

As of December 31, 2002, we owned various royalty and overriding royalty
interests in 1,336 net developed and 6,862 net undeveloped acres. In addition,
we owned 5,181 developed and 120,819 undeveloped mineral acres.

MAJOR CUSTOMERS

Our production is sold generally on month-to-month contracts at prevailing
prices. The following table identifies customers to whom we sold a significant
percentage of our total oil and gas production during each of the twelve-month
periods ended:

Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not result in a material adverse
effect on our ability to market future oil and gas production.

23

TITLE TO PROPERTIES

We believe that the title to our oil and gas properties is good and defensible
in accordance with standards generally accepted in the oil and gas industry,
subject to such exceptions which, in our opinion are not so material as to
detract substantially from the use or value of such properties. Our properties
are typically subject, in one degree or another, to one or more of the
following: royalties and other burdens and obligations, express or implied,
under oil and gas leases; overriding royalties and other burdens created by us
or our predecessors in title; a variety of contractual obligations (including,
in some cases, development obligations) arising under operating agreements,
farmout agreements, production sales contracts and other agreements that may
affect the properties or their titles; back-ins and reversionary interests
existing under purchase agreements and leasehold assignments; liens that arise
in the normal course of operations, such as those for unpaid taxes, statutory
liens securing obligations to unpaid suppliers and contractors and contractual
liens under operating agreements; pooling, unitization and communitization
agreements, declarations and orders; and easements, restrictions, rights-of-way
and other matters that commonly affect property. To the extent that such burdens
and obligations affect our rights to production revenues, they have been taken
into account in calculating our net revenue interests and in estimating the size
and value of our reserves. We believe that the burdens and obligations affecting
our properties are conventional in the industry for properties of the kind owned
by us.

ITEM 3. LEGAL PROCEEDINGS

We are a defendant in various legal proceedings and claims, which arise in the
ordinary course of our business. We do not believe the ultimate resolution of
any such actions will have a material affect on our financial position or
results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the fourth
quarter of 2002.

PART II.

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

Our common stock trades on the New York Stock Exchange under the symbol "CPE".
The following table sets forth the high and low sale prices per share as
reported for the periods indicated.

As of March 7, 2003, there were approximately 4,896 common stockholders of
record.

We have never paid dividends on our common stock and intend to retain our cash
flow from operations, net of preferred stock dividends, for the future operation
and development of our business. In addition, our primary credit facility and
the terms of our outstanding subordinated debt restrict payments of dividends on
our common stock.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth, as of the dates and for the periods indicated,
selected financial information about us. The financial information for each of
the five years in the period ended December 31, 2002 has been derived from our
audited Consolidated Financial Statements for such periods. The information
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements and Notes thereto. The following information is not necessarily
indicative of our future results.

CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

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

We use the full-cost method of accounting. Under this method of accounting, our
net capitalized costs to acquire, explore and develop oil and gas properties may
not exceed the standardized measure of our proved reserves. If these capitalized
costs exceed a ceiling amount, the excess is charged to expense. As a result of
the significant decline in oil and gas prices, we recorded a non-cash impairment
expense related to our oil and gas properties in the amount of $43.5 million
during the fourth quarter of 1998.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The following discussion is intended to assist in an understanding of our
financial condition and results of operations. Our Financial Statements and
Notes thereto contain detailed information that should be referred to in
conjunction with the following discussion. See Item 8. "Financial Statements and
Supplementary Data."

GENERAL

Callon Petroleum Company has been engaged in the exploration, development,
acquisition and production of oil and gas properties since 1950. Our revenues,
profitability and future growth and the carrying value of our oil and gas
properties are substantially dependent on prevailing prices of oil and gas and
our ability to find, develop and acquire additional oil and gas reserves that
are economically recoverable. Our ability to maintain or increase our borrowing
capacity and to obtain additional capital on attractive terms is also influenced
by oil and gas prices.

25

Our estimated net proved oil and gas reserves decreased at December 31, 2002 to
236 billion cubic feet of natural gas equivalent (Bcfe). This represents a
decrease of 22% over previous year-end 2001 estimated proved reserves of 303
Bcfe.

A major revision to reserves in 2002 was at our Boomslang discovery. The initial
exploratory well drilled at this location in 1998 encountered 185 feet of pay.
The well was drilled with mechanical problems and was subsequently determined
not to be a viable well for completion and production of the estimated proved
reserves encountered in this initial well. A second well, drilled in the fourth
quarter of 2002, to serve as a production take point, was drilled in a down dip
direction from the first well targeting what was anticipated to be a better sand
development in the three separate reservoirs found in the first well, but still
up dip of the lowest known hydrocarbons in the first well. Reservoir sand
quality changed dramatically, reducing the estimated reservoir volumes found and
booked as estimated proved reserves by the first well to an extent that the
partners determined that the risk of development was not economic. Callon had a
40% working interest. The Company's proved reserves in the prior year included
7.2 million barrels of oil and 13 billion cubic feet of natural gas attributable
to Boomslang.

Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include weather conditions in the United States, the condition of the
United States economy, the actions of the Organization of Petroleum Exporting
Countries, governmental regulation, political stability in the Middle East and
elsewhere, the foreign supply of crude oil and natural gas, the price of foreign
imports and the availability of alternate fuel sources. Any substantial and
extended decline in the price of crude oil or natural gas would have an adverse
effect on our carrying value of our proved reserves, borrowing capacity,
revenues, profitability and cash flows from operations. We use derivative
financial instruments (see Note 6 and Item 7A. "Quantitative and Qualitative
Disclosures About Market Risks") for price protection purposes on a limited
amount of our future production and do not use them for trading purposes. On a
Mcfe basis, natural gas represents 65% of the budgeted 2003 production and 39%
of proved reserves at year-end 2002.

Inflation has not had a material impact on us and is not expected to have a
material impact on us in the future.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

RECENT ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting
Standards Board issued Statement of Financial Accounting Standards No. 133
("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities. The
Statement establishes accounting and reporting standards requiring that every
derivative instrument, including certain derivative instruments embedded in
other contracts, be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS 133 requires the Company to report
changes in the fair value of our derivative financial instruments that qualify
as cash flow hedges in other comprehensive income, a component of stockholders'
equity, until realized. We adopted SFAS 133 effective January 1, 2001.

In June 2001, the Financial Accounting Standards Board approved Statement of
Accounting Standards No. 143, Asset Retirement Obligations ("SFAS 143"). SFAS
143 addresses financial accounting and reporting for obligations associated with
the retirement of tangible long-lived assets and the associated asset retirement
costs. We will record the fair value of these obligations on January 1, 2003, as
well as the related additional assets. The net difference between our previously
recorded abandonment liability and the amounts estimated under SFAS 143, after
taxes, is expected to total a gain of approximately $180,000, which will

26

be recognized as a cumulative effect of a change in accounting principle and an
expected abandonment liability for retirement obligations of approximately $26
million.

In December 2002, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 148 ("SFAS 148"), "Accounting for Stock-Based
Compensation-Transition and Disclosure -an amendment of SFAS No. 123." SFAS 148
amends SFAS 123 to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements of
SFAS 123 to require disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on the reported results. SFAS 148 is effective for the
year ended December 31, 2002 and for interim financial statements commencing in
2003. The adoption of this pronouncement by the Company did not have an impact
on our financial condition or results of operations.

PROPERTY AND EQUIPMENT. We follow the full-cost method of accounting for oil and
gas properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain overhead
costs, are capitalized into the "full cost pool." The amounts we capitalize into
the full cost pool are depleted (charged against earnings) using the
unit-of-production method. The full cost method of accounting for our proved oil
and gas properties requires that we make estimates based on assumptions as to
future events which could change. These estimates are described below.

Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We
calculate depletion by using the capitalized costs in our full cost pool plus
future development and abandonment costs (combined, the depletable base) and our
estimated net proved reserve quantities. Capitalized costs added to the full
cost pool and other costs added to the depletable base include the following:

o The cost of drilling and equipping productive wells, dry hole costs,
acquisition costs of properties with proved reserves, delay rentals and
other costs related to exploration and development of our oil and gas
properties;

o Our payroll and general and administrative costs and costs related
fringe benefits paid to employees directly engaged in the acquisition,
exploration and/or development of oil and gas properties as well as
other directly identifiable general and administrative costs associated
with such activities. Such capitalized costs do not include any costs
related to our production of oil and gas or our general corporate
overhead;

o Costs associated with properties that do not have proved reserves
attributed to them are excluded from the full cost pool. These
unevaluated property costs are added to the full cost pool at such time
as wells are completed on the properties, the properties are sold or we
determine these costs have been impaired. Our determination that a
property has or has not been impaired (which is discussed below)
requires that we make assumptions about future events.

o Our estimates of future costs to develop proved properties are added to
the full cost pool for purposes of the DD&A computation. We use
assumptions based on the latest geologic, engineering, regulatory and
cost data available to us to estimate these amounts. However, the
estimates we make are subjective and may change over time. Our
estimates of future development costs are periodically updated as
additional information becomes available.

o Estimated costs to dismantle, abandon and restore a proved property are
added to the full cost pool for the purposes of DD&A. Such cost
estimates are periodically updated as additional information becomes
available. As discussed above under Accounting Pronouncements,
specifically FAS 143, beginning January 1, 2003, we will change the
method for which we account for such costs

27

Capitalized costs included in the full cost pool are depleted and charged
against earnings using the unit of production method. Under this method, we
estimate our quantity of proved reserves at the beginning of each accounting
period. For each barrel of oil equivalent produced during the period, we record
a depletion charge equal to the amount included in the depletable base (net of
accumulated depreciation, depletion and amortization) divided by our estimated
net proved reserve quantities.

Because we use estimates and assumptions to calculate proved reserves (as
discussed below) and the amounts included in the full cost pool, our depletion
calculations will change as the estimates and assumptions are not realized. Such
changes may be material.

Ceiling Test. Under the full cost accounting rules, capitalized costs included
in the full cost pool, net of accumulated depreciation, depletion and
amortization (DD&A) and deferred income taxes, may not exceed the present value
of our estimated future net cash flows from proved oil and gas reserves,
discounted at 10 percent, plus the lower of cost or fair value of unproved
properties included in the costs being amortized, net of related tax effects.
These rules generally require that, in estimating future net cash flow, we
assume that future oil and gas production will be sold at the unescalated market
price for oil and gas received at the end of each fiscal quarter and that future
costs to produce oil and gas will remain constant at the prices in effect at the
end of the fiscal quarter. We are required to write-down and charge to earnings
the amount, if any, by which these costs exceed the discounted future net cash
flows, unless prices recover sufficiently before the date of our financial
statements. Given the volatility of oil and gas prices, it is likely that our
estimates of discounted future net cash flows from proved oil and gas reserves
will change in the near term. If oil and gas prices decline significantly, even
if only for a short period of time, it is possible that writedowns of oil and
gas properties could occur in the future.

Estimating Reserves and Present Values. Our estimates of quantities of proved
oil and gas reserves and the discounted present value of such reserves at the
end of each quarter are based on numerous assumptions which are likely to change
over time. These assumptions include:

o The prices at which we can sell our oil and gas production in the
future. Oil and gas process are volatile, but we are generally required
to assume that they will not change from the prices in effect at the
end of the quarter. In general, higher oil and gas prices will increase
quantities of proved reserves and the present value of such reserves,
while lower prices will decrease these amounts. Because our properties
have relatively short productive lives, changes in prices will affect
the present value more than quantities of oil and gas reserves.

o The costs to develop and produce our reserves and the costs to
dismantle our production facilities when reserves are depleted. These
costs are likely to change over time, but we are required to assume
that costs in effect at the end of the quarter will not change.
Increases in costs will reduce oil and gas quantities and present
values, while decreases in costs will increase such amounts. Because
our properties have relatively short productive lives, changes in costs
will affect the present value more than quantities of oil and gas
reserves.

In addition, the process of estimating proved oil and gas reserves requires that
our independent and internal reserve engineers exercise judgment based on
available geological, geophysical and technical information. We have described
the risks associated with reserve estimation and the volatility of oil and gas
prices, under "Risk Factors."

Unproved Properties. Costs associated with properties that do not have proved
reserves, including capitalized interest, are excluded from the full cost pool.
These unproved properties are included in the line item "Unevaluated properties
excluded from amortization." Unproved property costs are transferred to the full
cost pool when wells are completed on the properties or the properties are sold.
In addition, we are required to

28

determine whether our unproved properties are impaired and, if so, add the costs
of such properties to the full cost pool. We determine whether an unproved
property should be impaired by periodically reviewing our exploration program on
a property by property basis. This determination may require the exercise of
substantial judgment by our management.

DERIVATIVES. We use derivative financial instruments for price protection
purposes on a limited amount of our future production and do not use them for
trading purposes. Such derivatives were accounted for in years prior to 2001 as
hedges and have been recognized as an adjustment to oil and gas sales in the
period in which they are related. Current accounting treatment is under SFAS
133.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of capital are cash flows from operations, borrowings from
financial institutions and the sale of debt and equity securities. Net cash and
cash equivalents decreased during 2002 by $1.1 million. Cash provided from
operating activities during 2002 totaled $12.2 million. Dividends paid on
preferred stock were $1.3 million. Average debt outstanding was $246.0 million
during 2002 compared to $164.9 million in 2001. At December 31, 2002, we had
working capital of $.6 million.

In early July of 2001, we closed a $95 million multiple advance term loan
("Senior Notes") with a private lender. We drew $45 million on July 3, 2001 and
paid down our revolving Credit Facility. We drew the remaining $50 million in
December 2001. Under the terms of the agreement, we also issued warrants for the
purchase, at a nominal exercise price, of 265,210 shares of our common stock to
the lender and conveyed an overriding royalty interest equal to 2% of our net
interest in four of our deepwater discoveries. The warrants and the overriding
royalty interest were earned by the lender based on the ratio of the amount of
the loan proceeds advanced to the total loan facility amount. This senior debt
will mature March 31, 2005 and contains restrictions on certain types of future
indebtedness and dividends on common stock.

Effective October 31, 2000, we entered into a $75 million Credit Facility with
First Union National Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of our producing oil and gas properties and
guaranteed by our subsidiaries. On June 30, 2002, the lenders under the
Company's Credit Facility agreed to increase availability under the revolving
borrowing base from $50 million to $75 million.

The Credit Facility, the Senior Notes and our subordinated debt contain various
covenants including restrictions on additional indebtedness and payment of cash
dividends as well as maintenance of certain financial ratios. We are in
compliance with these covenants at December 31, 2002.

The holders of $22.9 million of the $36.0 million of the Company's 10.125%
Senior Subordinated Notes (the "Notes") consented to an extension of such Notes
until July 31, 2004. The Company granted 274,980 warrants with a fair market
value of approximately $1.3 million to purchase Common Stock of the Company and
paid consent fees in the amount of $2.3 million to the holders of the Notes that
granted the extensions. The holders of the Notes that did not consent to the
extension were paid on the maturity date of the Notes in September 2002.
Subsequent to September 2002, the holders of the Notes exercised approximately
116,000 warrants that were granted as a result of the extension of the Notes.

Our plans for 2003 include non-discretionary capital expenditures of $51.2
million. Approximately $8.6 million of this amount is allocated to the
completion of the Medusa deepwater discovery, currently scheduled to begin
production in the third quarter of 2003.

29

Following Medusa, the Habanero deepwater discovery is scheduled for development
with projected capital expenditures in 2003 of approximately $17.2 million and
is projected to begin initial production in the second half of 2003. Once
producing, this deepwater discovery is projected to have the same positive
impact on borrowing capacity as Medusa. Habanero will be produced through a
sidetrack of the initial discovery well and the additional development well to
be drilled in the summer of 2003. A sub sea completion will be routed into one
of the operator's existing facilities and initial production is expected in late
third quarter of 2003.

The Company anticipates that cash flow generated during 2003 and current
availability under the Credit Facility will provide necessary capital to enable
the Company to continue its operational activities until such time as production
from Medusa and Habanero begins. At that time, the Company anticipates that the
Medusa and Habanero reserves and production will be integrated into the
borrowing base of the Company's Credit Facility and will provide additional
available borrowing capacity. This increase in borrowing capacity as well as
significant additional cash flow from the new production will provide funds for
future discretionary capital expenditures.

The completion of the Company's deepwater discoveries will require the
construction of expensive production facilities and pipelines, including the
transportation and installation of production facilities and the use of sub sea
completion techniques. The Company cannot estimate the timing of the
construction of these facilities with certainty. The operators completing these
discoveries will possibly face inclement weather and other unfavorable
environmental conditions, delays in fabrication and delivery of necessary
equipment, and other unforeseen circumstances that may delay completion of these
properties. Long-term delays in the completion of these deepwater projects that
prevent the commencement of production from such discoveries could have a
material adverse effect on the Company's financial position and result of
operations. Such a delay would require the Company to reduce future anticipated
capital expenditures or seek additional sources of liquidity to finance capital
expenditures, which may not be available.

The following table describes our outstanding contractual obligations (in
thousands) as of December 31, 2002:

RESULTS OF OPERATIONS

The following table sets forth certain operating information with respect to our
oil and gas operations for each of the three years in the period ended December
31, 2002.

30

(a) Includes hedging gains and losses.

(b) Includes volumes of 1,200 MMcf for the year 2002 and 2,300 MMcf for each of
the years 2001 and 2000, at an average price of $2.08 per Mcf associated with a
volumetric production payment.

PENDING SEC REVIEW OF RESERVE INFORMATION

In October 2002 and February 2003, we received letters from the SEC regarding
our Annual Report on Form 10-K for the year ended December 31, 2001 requesting
supplemental information concerning our operations in the Gulf of Mexico. The
comment letters requested information about the procedures we used to classify
our deepwater reserves as proved and requested that our financials be restated
to reflect the removal of the Boomslang reserves as proved for all prior periods
during which such reserves were reported as proved. We have reviewed the SEC
comments with our independent petroleum reserve engineers, Huddleston & Co.,
Inc. of Houston, Texas. Both Huddleston & Co and Callon believe that such
deepwater reserves are properly classified as proved.

COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND
2001

OIL AND GAS REVENUES

Oil and gas revenues for 2002 were $61.2 million, a 2% increase from the 2001
amount of $60.0 million. 2002 oil and gas production of 15,571 MMcfe increased
as well from the 2001 amount of 15,206 MMcfe.

Oil production decreased from 273,000 barrels in 2001 to 226,000 barrels in 2002
but the average sales price increased from $22.95 in 2001 to $23.11 in 2002. As
a result, oil revenues dropped from $6.3 million in 2001 to $5.2 million in
2002. The production decrease was primarily due to older properties' normal and
expected decline in production.

Gas revenues for 2002 were $55.9 million based on sales of 14.2 Bcf at an
average sales price of $3.94 per Mcf. For 2001, gas revenues were $53.7 million
based on production of 13.6 Bcf sold at an average sales price of $3.96 per Mcf.
Our gas production in 2002 increased when compared to last year due primarily to
the acceleration program at Mobile Blocks 952/953/955 area initiated in the
fourth quarter of 2001.

31

LEASE OPERATING EXPENSES

Lease operating expenses remained relatively stable at $11.3 million ($.73 per
Mcfe) in 2001 compared to $11.0 million ($.71 per Mcfe) in 2002.

DEPRECIATION, DEPLETION AND AMORTIZATION

Depreciation, depletion and amortization increased by 28% due in large part to
the downward reserve revisions at Boomslang. This decrease in estimated proved
reserves, over which depletable costs are amortized, increased the per unit
depletion rate, while production remained relatively constant between years.

Total charges increased from $21.1 million or $1.39 per Mcfe in 2001, to $27.1
million, or $1.74 per Mcfe in 2002.

GENERAL AND ADMINISTRATIVE

General and administrative expenses for 2002 were $4.7 million, or $.30 per
Mcfe, compared to $4.6 million, or $.30 per Mcfe, in 2001.

INTEREST EXPENSE

Interest expense for 2002 was $26.1 million increasing from $12.8 million in
2001. This is a result of an increase in our long-term debt as well as higher
interest rates associated with additional debt incurred in 2002.

INCOME TAXES

Our 2002 results include a deferred income tax benefit of $900,000. We evaluated
the deferred income tax asset in light of our reserve quantity estimates, our
long-term outlook for oil and gas prices and our expected level of future
revenues and expenses. We believe it is more likely than not, based upon this
evaluation, that we will realize the recorded deferred income tax asset.
However, there is no assurance that such asset will ultimately be realized.

COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001 AND
2000

OIL AND GAS REVENUES

Oil and gas revenues for 2001 were $60.0 million, a 7% increase from the 2000
amount of $56.3 million. However, 2001 oil and gas production of 15,206 MMcfe
decreased slightly from the 2000 amount of 15,334 MMcfe.

Oil production increased from 232,000 barrels in 2000 to 273,000 barrels in 2001
but the average sales price decreased from $27.88 in 2000 to $22.95 in 2001. As
a result, oil revenues dropped from $6.5 million in 2000 to $6.3 million in
2001. The production increase was primarily from increased oil production at
South Marsh Island 261 offset by older properties' normal and expected decline
in production. The slight decrease in oil revenue was due to the decline in
average oil prices received in 2001.

Gas revenues for 2001 were $53.7 million based on sales of 13.6 Bcf at an
average sales price of $3.96 per Mcf. For 2000, gas revenues were $49.8 million
based on production of 13.9 Bcf sold at an average sales price of $3.57 per Mcf.
Our gas production in 2001 decreased when compared to last year as a result of

32

production declines at East Cameron 275 and South Marsh Island 261, offset by
increases in production at Mobile Block 864 and Chandeleur Block 40. The
production declines at East Cameron 275 and South Marsh Island 261 were normal
and expected as the 2000 rates were indicative of higher initial production. The
Mobile Block 864 Area increased production due to a well stimulation program as
well additions to production through exploratory and developmental drilling on
the property. Gas revenue increased due to higher prices received for production
in 2001.

LEASE OPERATING EXPENSES

Lease operating expenses increased from $9.3 million ($.61 per Mcfe) in 2000 to
$11.3 million ($.73 per Mcfe) in 2001. The increase was attributable to higher
operating costs at South Marsh Island 261 and at Mobile Block 864. Also,
production declines related to older properties that have relatively fixed
operating costs contributed to the higher per Mcf costs with lower production
levels for those properties in 2001.

WRITEDOWN OF ENRON DERIVATIVES

In April of 2001, we entered into derivative contracts for 2002 production with
Enron North America Corp. Enron North America Corp. filed for protection under
the bankruptcy laws in late 2001. As a result of the credit risk associated with
the derivatives with Enron North America Corp., hedge accounting was not
available due to ineffectiveness as of September 30, 2001 and the contracts at
December 31, 2001 were marked to the market. In the fourth quarter of 2001, we
charged to expense (non-cash) $9.2 million related to these Enron North America
Corp. derivatives. We have no other contracts with Enron or their related
subsidiaries.

DEPRECIATION, DEPLETION AND AMORTIZATION

Depreciation, depletion and amortization increased by 23% due to a combination
of an increase in the amortization base due to higher drilling costs with
reserve additions being less than expected from exploration efforts in 2001 and
downward reserve revisions in 2000 as a result of a field delineation program at
Habanero.

Total charges increased from $17.2 million, or $1.12 per Mcfe in 2000 to $21.1
million, or $1.39 per Mcfe in 2001.

GENERAL AND ADMINISTRATIVE

General and administrative expenses for 2001 were $4.6 million, or $.30 per
Mcfe, compared to $4.2 million, or $.27 per Mcfe, in 2000. This increase was due
primarily to expenses incurred in the second quarter of 2001 related to our
withdrawn debt offering.

INTEREST EXPENSE

Interest expense for 2001 was $12.8 million increasing from $8.4 million in
2000. This is a result of an increase in our long-term debt as well as higher
interest rates associated with additional debt incurred in 2001.

INCOME TAXES

Our 2001 results include a deferred income tax expense of $977,000. We evaluated
the deferred income tax asset in light of our reserve quantity estimates, our
long-term outlook for oil and gas prices and our expected level of future
revenues and expenses. We believe it is more likely than not, based upon this
evaluation, that we will realize the recorded deferred income tax asset.
However, there is no assurance that such asset will ultimately be realized.

33

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

The Company's revenues are derived from the sale of its crude oil and natural
gas production. In recent months, the prices for oil and gas have increased;
however, they remain extremely volatile and sometimes experience large
fluctuations as a result of relatively small changes in supplies, weather
conditions, economic conditions and government actions. The Company enters into
derivative financial instruments to hedge oil and gas price risks for the
production volumes to which the hedge relates. The derivatives reduce the
Company's exposure on the hedged volumes to decreases in commodity prices and
limit the benefit the Company might otherwise have received from any increases
in commodity prices on the hedged volumes.

The Company also enters into price "collars" to reduce the risk of changes in
oil and gas prices. Under these arrangements, no payments are due by either
party so long as the market price is above the floor price set in the collar and
below the ceiling. If the price falls below the floor, the counter-party to the
collar pays the difference to the Company and if the price is above the ceiling,
the counter-party receives the difference from the Company. The Company enters
into these various agreements to reduce the effects of volatile oil and gas
prices and does not enter into hedge transactions for speculative purposes. See
Note 6 to the Consolidated Financial Statements for a description of the
Company's hedged position at December 31, 2002. There have been no significant
changes in market risks faced by the Company since the end of 2002.

Based on projected annual sales volumes for 2003 (excluding forecast production
increases over 2002), a 10% decline in the prices we receive for our crude oil
and natural gas production would have an approximate $6.5 million impact on our
revenues.

34

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

35

REPORT OF INDEPENDENT AUDITORS

The Stockholders and Board of Directors
Callon Petroleum Company:

We have audited the accompanying consolidated balance sheet of Callon
Petroleum Company as of December 31, 2002, and the related consolidated
statements of operations, stockholders' equity and cash flows for the year then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit. The financial statements of Callon Petroleum
Company as of December 31, 2001 and for each of the two years in the period then
ended, were audited by other auditors who have ceased operations and whose
report dated March 29, 2002, expressed an unqualified opinion on those
statements and included an explanatory paragraph that disclosed the change in
the Company's method of accounting for derivative instruments and hedging
activities discussed in Note 2 to those financial statements.

We conducted our audit in accordance with auditing standards generally
accepted in the United States. 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 audit provides a reasonable basis
for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Callon
Petroleum Company as of December 31, 2002, and the results of its operations and
its cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States.

ERNST & YOUNG LLP

New Orleans, Louisiana
February 28, 2003

36

The following report is a copy of the audit report previously issued by Arthur
Andersen LLP in connection with Callon Petroleum Company's annual report on Form
10-K for the year ended December 31, 2001. This audit report has not been
reissued by Arthur Andersen LLP in connection with this filing on form 10-K for
the year ended December 31, 2002. The consolidated balance sheet as of December
31, 2000 and the consolidated statements of operations, stockholders' equity and
cash flows for the year ended December 31, 1999, mentioned in the report, are
not required in the Company's annual report for 2002 and are therefore not
presented among the financial statements in this annual report.

REPORT OF INDEPENDENT AUDITORS

To the Stockholders and Board of Directors of Callon Petroleum Company:

We have audited the accompanying consolidated balance sheets of Callon
Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 financial statements referred to above present
fairly, in all material respects, the financial position of Callon Petroleum
Company and subsidiaries, as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.

As discussed in Note 2 to the consolidated financial statements
effective January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities."

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
March 29, 2002

37

CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

The accompanying notes are an integral part of these financial statements.

38

CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

The accompanying notes are an integral part of these financial statements.

39

CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)

The accompanying notes are an integral part of these financial statements.

40

CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

The accompanying notes are an integral part of these financial statements.

41

CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

GENERAL

Callon Petroleum Company ("Company") was organized under the laws of the state
of Delaware in March 1994 to serve as the surviving entity in the consolidation
and combination of several related entities (referred to herein collectively as
the "Constituent Entities"). The combination of the businesses and properties of
the Constituent Entities with the Company was completed on September 16, 1994
("Consolidation").

As a result of the Consolidation, all of the businesses and properties of the
Constituent Entities are owned (directly or indirectly) by the Company. Certain
registration rights were granted to the stockholders of certain of the
Constituent Entities. See Note 7.

The Company and its predecessors have been engaged in the acquisition,
development and exploration of crude oil and natural gas since 1950. The
Company's properties are geographically concentrated in Louisiana, Alabama,
Texas and offshore Gulf of Mexico.

LIQUIDITY AND CAPITAL RESOURCES

In 2002, the lenders under the Company's Credit Facility agreed to increase
availability under the revolving borrowing base from $50 million to $75 million.
In addition, the holders of $22.9 million of the $36.0 million of the Company's
10.125% Senior Subordinated Notes ("Notes") consented to an extension of such
Notes until July 31, 2004. The Company granted 274,980 warrants with a fair
market value of approximately $1.3 million to purchase Common Stock of the
Company for $.01 per share and paid consent fees in the amount of $2.3 million
to the holders of the Notes that granted the extensions. The holders of the
Notes that did not consent to the extension were paid on the maturity date of
the Notes in September 2002. Subsequent to September 2002, the holders of the
Notes exercised approximately 116,000 warrants that were granted as a result of
the extension of the Notes.

Non-discretionary capital expenditures include completion of the Medusa
deepwater discovery, currently scheduled to begin production in the late summer
of 2003. The Company anticipates that cash flow generated during 2003 and
current availability under the Credit Facility will provide necessary capital to
enable the Company to continue its operational activities until such time as
production from the Medusa discovery begins. At that time, the Company
anticipates that the Medusa reserves and production will be integrated into the
borrowing base of the Company's Credit Facility and will provide additional
available borrowing capacity. This increase in borrowing capacity as well as
significant additional cash flow expected from the new production will provide
funds for future discretionary capital expenditures.

Following Medusa, the Habanero deepwater discovery is scheduled for development
and is projected to begin initial production in the second half of 2003. Once
producing, this deepwater discovery is projected to have the same positive
impact on borrowing capacity as Medusa. Habanero will be produced by the

42

existing delineation well and an additional well to be drilled in the summer of
2003. A sub sea completion will be routed into one of the operator's existing
facilities and initial production is expected in late third quarter of 2003.

The completion of the Company's deepwater discoveries will require the
construction of expensive production facilities and pipelines, including the
transportation and installation of production facilities and the use of sub sea
completion techniques. The Company cannot estimate the timing of the
construction of these facilities with certainty. The operators completing these
discoveries will possibly face inclement weather and other unfavorable
environmental conditions, delays in fabrication and delivery of necessary
equipment, and other unforeseen circumstances that may delay completion of these
properties. Long-term delays in the completion of these deepwater projects that
prevent the commencement of production from such discoveries could have a
material adverse effect on the Company's financial position and result of
operations. Such a delay would require the Company to reduce future anticipated
capital expenditures or seek additional sources of liquidity to finance capital
expenditures, which may not be available.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION AND REPORTING

The Consolidated Financial Statements include the accounts of the Company, and
its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has
subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing,
Inc. All intercompany accounts and transactions have been eliminated. Certain
prior year amounts have been reclassified to conform to presentation in the
current year.

USE OF ESTIMATES

The preparation of 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 financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.

ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative
Instruments and Hedging Activities. The Statement establishes accounting and
reporting standards requiring that every derivative instrument, including
certain derivative instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Company adopted SFAS 133 effective January 1, 2001. The cumulative effect of the
accounting change, net of tax, recorded as other comprehensive loss was $3.8
million.

SFAS 133 requires the Company to report changes in the fair value of our
derivative financial instruments that qualify as cash flow hedges in other
comprehensive income, a component of stockholders' equity, until realized. See
Note 6 for a discussion of our derivative financial instruments.

In June 2001, the Financial Accounting Standards Board approved Statement of
Accounting Standards No. 143, Asset Retirement Obligations ("SFAS 143"). SFAS
143 addresses financial accounting and reporting for obligations associated with
the retirement of tangible long-lived assets and the associated asset retirement
costs. We will record the fair value of these obligations on January 1, 2003, as
well as the related additional

43

assets. The net difference between our previously recorded abandonment liability
and the amounts estimated under SFAS 143, after taxes, is expected to total a
gain of approximately $180,000, which will be recognized as a cumulative effect
of a change in accounting principle and an expected abandonment liability for
retirement obligations of approximately $26 million.

In December 2002, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 148 ("SFAS 148"), "Accounting for Stock-Based
Compensation-Transition and Disclosure--an amendment of SFAS No. 123." SFAS 148
amends SFAS 123 to provide alternative methods of transition for a voluntary
change to the fair value based method of accounting for stock-based employee
compensation. In addition, this statement amends the disclosure requirements of
SFAS 123 to require disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on the reported results. SFAS 148 is effective for the
year ended December 31, 2002 and for interim financial statements commencing in
2003. The adoption of this pronouncement by the Company did not have an impact
on our financial condition or results of operations.

PROPERTY AND EQUIPMENT

The Company follows the full cost method of accounting for oil and gas
properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain overhead
costs, are capitalized. Such amounts include the cost of drilling and equipping
productive wells, dry hole costs, lease acquisition costs, delay rentals,
interest capitalized on unevaluated leases and other costs related to
exploration and development activities. Payroll and general and administrative
costs capitalized include salaries and related fringe benefits paid to employees
directly engaged in the acquisition, exploration and/or development of oil and
gas properties as well as other directly identifiable general and administrative
costs associated with such activities. Such capitalized costs ($9.6 million in
2002, $10.0 million in 2001 and $7.4 million in 2000) do not include any costs
related to production or general corporate overhead. Costs associated with
unevaluated properties, including capitalized interest on such costs, are
excluded from amortization. Unevaluated property costs are transferred to
evaluated property costs at such time as wells are completed on the properties,
the properties are sold or management determines these costs have been impaired.

Costs of properties, including future development and net future site
restoration, dismantlement and abandonment costs, which have proved reserves and
those which have been determined to be worthless, are depleted using the
unit-of-production method based on proved reserves. If the total capitalized
costs of oil and gas properties, net of amortization, exceed the sum of (1) the
estimated future net revenues from proved reserves at current prices and
discounted at 10% and (2) the lower of cost or market of unevaluated properties
(the full cost ceiling amount), net of tax effects, then such excess is charged
to expense during the period in which the excess occurs. See Note 8.

Upon the acquisition or discovery of oil and gas properties, management
estimates the future net costs to be incurred to dismantle, abandon and restore
the property using geological, engineering and regulatory data available. Such
cost estimates are periodically updated for changes in conditions and
requirements. Such estimated amounts are considered as part of the full cost
pool subject to amortization upon acquisition or discovery. Such costs are
capitalized as oil and gas properties as the actual restoration, dismantlement
and abandonment activities take place. As discussed above under Accounting
Pronouncements, beginning January 1, 2003, the Company will change the method
for which we account for such cost as described by FAS 143.

44

Depreciation of other property and equipment is provided using the straight-line
method over estimated lives of three to 20 years. Depreciation of pipeline and
other facilities is provided using the straight-line method over estimated lives
of 15 to 27 years.

SALE OF PRODUCTION PAYMENT INTEREST

In June 1999, the Company acquired a working interest in the Mobile Block 864
Area where the Company already owned an interest. Concurrent with this
acquisition, the seller received a volumetric production payment, valued at
approximately $14.8 million, from production attributable to a portion of the
Company's interest in the area over a 39-month period. The Company recorded a
liability associated with the sale of this production payment interest because a
substantial obligation for future performance existed. Under the terms of the
sale, the Company was obligated to deliver the production volumes free and clear
of royalties, lease operating expenses, production taxes and all capital costs.
The production payment was amortized, beginning in June 1999, to oil and gas
sales on the units-of-production method as associated hydrocarbons were
delivered, and expired in July 2002.

NATURAL GAS IMBALANCES

The Company follows an entitlement method of accounting for its proportionate
share of gas production on a well-by-well basis, recording a receivable to the
extent that a well is in an "undertake" position and conversely recording a
liability to the extent that a well is in an "overtake" position. Imbalance
positions are not significant at December 31, 2002.

DERIVATIVES

The Company uses derivative financial instruments for price protection purposes
on a limited amount of its future production and does not use them for trading
purposes. Such derivatives were accounted for, prior to adoption of SFAS 133, as
hedges and have been recognized as an adjustment to oil and gas sales in the
period in which they are related. Current accounting treatment is under SFAS 133
(see Note 6).

ACCOUNTS RECEIVABLE

Accounts receivable consists primarily of accrued oil and gas production
receivables. The balance in the reserve for doubtful accounts included in
accounts receivable was $143,000 and $68,000 at December 31, 2002 and 2001,
respectively. Net recoveries were $75,000 in 2002 and net charge offs were
$10,000 in 2001. There were no provisions to expense in the three-year period
ended December 31, 2002.

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES TO BE REFINANCED

These amounts included in the Balance Sheet represent capital expenditures in
accounts payable and accrued liabilities that were refinanced with the
availability under the Credit Facility subsequent to December 31, 2002. Amounts
in 2001 were classified as short term because of the maturity of the Credit
Facility at December 31, 2001. See Footnote 5 for a discussion of the amendment
to the Credit Facility in June of 2001.

45

STOCK BASED COMPENSATION

The Company accounts for its stock based compensation plans under the
recognition and measurement principles of APB Opinion No. 25, Accounting for
Stock Issued to Employees, and related Interpretations. See Footnote 10 for
descriptions and additional disclosures related to the plans.

MAJOR CUSTOMERS

Our production is sold generally on month-to-month contracts at prevailing
prices. The following table identifies customers to whom we sold a significant
percentage of our total oil and gas production during each of the twelve-month
periods ended:

Because alternative purchasers of oil and gas are readily available, we believe
that the loss of any of these purchasers would not result in a material adverse
effect on our ability to market future oil and gas production.

STATEMENTS OF CASH FLOWS

For purposes of the Consolidated Financial Statements, the Company considers all
highly liquid investments purchased with an original maturity of three months or
less to be cash equivalents.

The Company paid no federal income taxes for the three years ended December 31,
2002. During the years ended December 31, 2002, 2001 and 2000, the Company made
cash payments for interest of $25,507,000, $16,441,000 and $11,449,000
respectively.

PER SHARE AMOUNTS

Basic income or loss per common share was computed by dividing net income or
loss by the weighted average number of shares of common stock outstanding during
the year. Diluted income or loss per common share was determined on a weighted
average basis using common shares issued and outstanding adjusted for the effect
of stock options considered common stock equivalents computed using the treasury
stock method. The conversion of the preferred stock was not included in any
annual calculation due to its antidilutive effect on diluted income or loss per
common share.

46

A reconciliation of the basic and diluted per share computation is as follows
(in thousands, except per share amounts):

FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value of cash, cash equivalents, accounts receivable, accounts payable, the
capital lease and the Credit Facility approximates book value at December 31,
2002 and 2001. Fair value of long-term debt (specifically, the 10.125%, the
10.25%, the 11% Senior Subordinated Notes and the 12% Senior Notes) have an
estimated fair value of between 84% and 86% of face value at December 31, 2002.

3. INCOME TAXES

The Company follows the asset and liability method of accounting for deferred
income taxes prescribed by Statement of Financial Accounting Standards No. 109
("SFAS 109") "Accounting for Income Taxes". The statement provides for the
recognition of a deferred tax asset for deductible temporary timing differences,
capital and operating loss carryforwards, statutory depletion carryforward and
tax credit carryforwards, net of a "valuation allowance". The valuation
allowance is provided for that portion of the asset, for which it is deemed more
likely than not, that it will not be realized. The Company's management
determined that no valuation allowance was required in 2002 or 2001.
Accordingly, the Company has recorded a deferred tax asset at December 31, 2002
and 2001 as follows:

47

At December 31, 2002, the Company had, for federal tax reporting purposes, net
operating loss carryforwards of $121.3 million, which expire in 2003 through
2017. Net operating loss carryforwards includes approximately $1.4 million of
the total that will expire within the next five years including approximately $1
million in 2003. Additionally, the Company had available for tax reporting
purposes $12.0 million in statutory depletion deductions, which can be carried
forward for an indefinite period. No valuation allowance has been provided
against these carryforwards because management believes that it is more likely
than not they will be realized. However, realization is not assured.

The Company has significant state net operating loss carryforwards that are not
included in the deferred tax asset above, as the Company does not anticipate
generating taxable state income in the states in which these loss carryforwards
apply. The Company has very limited state taxable income as primarily all of its
revenue is generated in federal waters not subject to state income taxes.

The provision for income taxes at the Company's effective tax rate approximated
the provision for income taxes at the statutory rate.

4. OTHER COMPREHENSIVE INCOME

The Company did not have any items of other comprehensive income prior to 2001.
A recap of the Company's 2002 and 2001 comprehensive income (net of tax) is
shown below (in thousands):

48

5. LONG-TERM DEBT

Long-term debt consisted of the following at:

The Company negotiated its Credit Facility effective October 31, 2000 with First
Union National Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. On June 30, 2002, the Company amended the Credit Facility to
increase availability under the revolving borrowing base from $50 million to $75
million under a dual tranche loan. The Tranche A revolver bears interest at
0.25% to 0.75% above a defined base rate depending on utilization of the
borrowing base or, at the option of the Company, LIBOR plus 2% to 2.5% based on
utilization of the borrowing base and has a maximum aggregate credit amount of
$45 million. The range of interest rates on the Tranche A revolver was 3.36% to
5.25% for the twelve months ended December 31, 2002. The Tranche B part of the
facility will bear interest at 15% and has an aggregate maximum credit amount of
$30 million. The amended Credit Facility contains substantially the same
covenants as the original Credit Facility. The weighted average interest rate
for the Credit Facility debt outstanding at December 31, 2002 and 2001 was 9.00%
and 4.75%, respectively. Under the Credit Facility, a commitment fee of 0.25% or
0.375% per annum, depending on the amount of the unused portion of the borrowing
base, is payable quarterly. The maturity date of the Credit Facility is June 30,
2004 and the $75 million borrowing base is subject to semi-annual
re-determinations in April and October of each year.

On September 15, 2002, $36 million of the Company's 10.125% Senior Subordinated
Notes ("Notes")that were issued on July 31, 1997, were due. The holders of $22.9
million of the Notes consented to an extension of such Notes until July 31,
2004. The Company granted 274,980 warrants (with a fair market value of
approximately $1.3 million) to purchase Common Stock of the Company and paid
consent fees in the amount of $2.3 million to the holders of the Notes that
granted the extensions. The warrants have a term of five years and an exercise
price of $0.01. The holders of the Notes had exercised approximately 116,000
warrants as of December 31, 2002. The holders of the Notes that did not consent
to the extension were paid on the maturity date in September 2002. Interest on
the Notes is payable quarterly, on March 15, June 15, September 15, and December
15 of each year.

The Company accounted for the extension of the $22.9 million in Notes described
above as an extinguishment of the Notes and the issuance of new securities
recorded at a fair value of $19.3 million.

49

The net loss on extinguishment, including the warrants and fees paid described
above was not significant. Costs deferred with the extensions will be amortized
through July 2004.

On July 15, 1999, the Company completed the sale of $40 million of Senior
Subordinated Notes due 2004 at 10.25%. The net proceeds of approximately $38.2
million were used to pay down the Credit Facility at that time. These notes are
not entitled to any mandatory sinking fund payments and are subject to
redemption at the Company's option at par plus unpaid interest at any time after
March 15, 2001. The notes are listed on the New York Stock Exchange under the
symbol "CPE 04" and are subject to a change of control clause that obligates the
Company to repurchase the notes for 101% of par should a change of control
occur. Interest is paid quarterly.

The Company completed the sale of $33 million of 11% Senior Subordinated Notes
due 2005, on October 26, 2000. The Company netted $31.5 million from the
offering after deducting the underwriters' discount and offering expenses.
Approximately $20.8 million of the net proceeds from the offering were used to
purchase a portion of the Company's outstanding 10% Senior Subordinated Notes
due 2001 in conjunction with a tender offer. The Company redeemed the remaining
$3.4 million of its 10% Senior Subordinated Notes due 2001 not tendered in the
offer.

In July 2001, the Company entered into a $95 million multiple advance term loan
("Senior Notes") with a private lender. The Company issued $45 million of 12%
Senior Notes upon closing of the loan and issued the remaining $50 million of
Senior Notes in December 2001. Under the terms of the agreement Callon also
issued warrants to purchase, at a nominal exercise price, 265,210 shares of its
common stock (fair value of $3.1 million) and conveyed an overriding royalty
interest equal to 2% of the Company's net interest in four existing deepwater
discoveries (fair value of $5.9 million). The warrants and the overriding
royalty interest were earned by the lender based on the ratio of the amount of
the loan proceeds advanced to the total loan facility amount. The Senior Notes
will mature March 31, 2005, have an effective interest rate of approximately 16%
and contain restrictions on certain types of future indebtedness.

In December 2001, the Company entered into a ten-year gas processing agreement
associated with a production facility on Callon's Mobile 952 field with Hanover
Compression Limited Partnership, which is being accounted for as a capital
lease. Total minimum obligations are $8.4 million with interest representing
approximately $2.8 million and the present value minimum obligations were $5.6
million ($1.2 million current).

Future minimum lease payments and debt maturities (in thousands) are as follows:

The Credit Facility, the subordinated debt and the Senior Notes contain various
covenants including restrictions on additional indebtedness and payment of cash
dividends as well as maintenance of certain financial ratios. The Company is in
compliance with these covenants at December 31, 2002.

50

6. DERIVATIVES

The Company periodically uses derivative financial instruments to manage oil and
gas price risk. Settlements of gains and losses on commodity price contracts are
generally based upon the difference between the contract price or prices
specified in the derivative instrument and a NYMEX price or other cash or
futures index price. As a result of these contracts, there was no effect on oil
and gas revenue during 2002 and in 2001, $1,371,000 was recognized as additional
oil and gas revenue.

In 2002, the Company purchased and sold various put options and call options and
elected not to designate these derivative financial instruments as accounting
hedges and accordingly, accounted for these contracts under mark-to-market
accounting. Year-to-date charges to income were $708,000.

During 2002, the Company entered into no-cost natural gas collar contracts in
effect for February 2003 through October 2003. These agreements are for volumes
of 275,000 Mcf per month with an average ceiling price of $4.79 and a floor
price of $3.52. These contracts are accounted for as cash flow hedges under SFAS
133. The fair value of these collar contracts at December 31, 2002, recorded on
the balance sheet is $721,350 and $468,878 (net of tax) as other comprehensive
income.

In April 2001, the Company entered into derivative contracts for 2002 production
with Enron North America Corp. These agreements are for average gas volumes of
approximately 600,000 Mcf per month in 2002 with a weighted average ceiling
price of $6.09 and floor price of $4.11. Enron North America Corp. filed for
protection under the bankruptcy laws in late 2001. As a result of the credit
risk associated with the derivatives with Enron North America Corp., hedge
accounting was not available due to ineffectiveness as of September 30, 2001 and
the contracts at December 31, 2001 were marked to the market. In the fourth
quarter of 2001, the Company charged to expense (non-cash) $9.2 million related
to these Enron North America Corp. derivatives. The Company has no other
contracts with Enron or its subsidiaries.

The $5,971,000 (net of tax) recorded in other comprehensive income at December
31, 2001 is related to the fair value as of September 30, 2001 of the natural
gas collar contracts with Enron North America Corp., which matured in 2002. As
the contracts matured, the Company recorded non-cash revenue each month,
offsetting the amounts in other comprehensive income related to the derivatives.
The Company recorded approximately $1.7 million related to these Enron
derivatives in the fourth quarter of 2002 and $9.2 million for the year ended
December 31, 2002 as oil and gas revenue.

In the second quarter of 2002, the Company completed the sale of its claim
against Enron for hedging transactions for $2.5 million in cash. As a result of
the sale, the Company reported a pre-tax gain of $2.5 million in the second
quarter of 2002.

The Company has no other derivative contracts.

51

7. COMMITMENTS AND CONTINGENCIES

As described in Note 9, abandonment trusts (the "Trusts") have been established
for future abandonment obligations of those oil and gas properties of the
Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses in
excess of the Trusts' balances. As of December 31, 2002, total estimated site
restoration, dismantlement and abandonment costs were approximately $6,896,000,
net of expected salvage value. Substantially all such costs are expected to be
funded through the Trusts' funds, all of which will be accessible to the Company
when abandonment work begins. In addition, as a working interest owner and/or
operator of oil and gas properties, the Company is responsible for the cost of
abandonment of such properties. See Note 2.

From time to time, the Company, as part of the Consolidation and other capital
transactions, entered into Registration Rights Agreements whereby certain
parties to the transactions are entitled to require the Company to register
Common Stock of the Company owned by them with the Securities and Exchange
Commission for sale to the public in firm commitment public offerings and
generally to include shares owned by them, at no cost, in registration
statements filed by the Company. Costs of the offering will not include broker's
discounts and commissions, which will be paid by the respective sellers of the
Common Stock.

The Company is involved in various claims and lawsuits incidental to its
business. In the opinion of management, the ultimate liability thereunder, if
any, will not have a material adverse effect on the financial position or
results of operations of the Company.

The Company's activities are subject to federal, state and local laws and
regulations governing environmental quality and pollution control. Although no
assurances can be made, the Company believes that, absent the occurrence of an
extraordinary event, compliance with existing federal, state and local laws,
rules and regulating the release of materials in the environment or otherwise
relating to the protection of the environment will not have a material effect
upon the capital expenditures, earnings or the competitive position of the
Company with respect to its existing assets and operations. The Company cannot
predict what effect additional regulation or legislation, enforcement polices
thereunder, and claims for damages to property, employees, other persons and the
environment resulting from the Company's operations could have on its
activities.

52

8. OIL AND GAS PROPERTIES

The following table discloses certain financial data relating to the Company's
oil and gas activities, all of which are located in the United States.

Unevaluated property costs, primarily lease acquisition costs incurred at
federal lease sales, unevaluated drilling costs, capitalized interest and
general and administrative costs being excluded from the amortizable evaluated
property base consisted of $9.4 million incurred in 2002, $7.5 million incurred
in 2001 and $24.1 million incurred in 2000 and prior. These costs are directly
related to the acquisition and evaluation of unproved properties and major
development projects. The excluded costs and related reserves are included in
the amortization base as the properties are evaluated and proved reserves are
established or impairment is determined. The Company expects that the majority
of these costs will be evaluated over the next three to five year period.

Depletion per unit-of-production (thousand cubic feet of gas equivalent)
amounted to $1.73, $1.37 and $1.10 for the years ended December 31, 2002, 2001,
and 2000, respectively.

Under the full cost accounting rules of the SEC, the Company reviews the
carrying value of its proved oil and gas properties each quarter. Under these
rules, capitalized costs of proved oil and gas properties net of accumulated
depreciation, depletion and amortization (DD&A) and deferred income taxes, may
not exceed the present value of estimated future net cash flows from proved oil
and gas reserves, discounted at 10 percent, plus the lower of cost or fair value
of unproved properties included in the costs being amortized, net of related tax
effects. These rules generally require pricing future oil and gas production at
the unescalated market price for oil and gas at the end of each fiscal quarter
and require a write-down if the "ceiling" is exceeded, unless prices recover
sufficiently before the date of the auditor's report. Given the volatility of
oil and gas prices, it is reasonably possible that the Company's estimate of
discounted future net cash flows from proved oil and gas reserves could change
in the near term. If oil and gas priced decline significantly, even if only for
a short period of time, it is possible that writedowns of oil and gas properties
could occur in the future.

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9. NET PROFITS INTEREST

From 1989 through 1994, the Constituent Entities entered into separate
agreements to purchase certain oil and gas properties with gross contract
acquisition prices of $170,000,000 ($150,000,000 net as of closing dates) and in
simultaneous transactions, entered into agreements to sell overriding royalty
interests ("ORRI") in the acquired properties. These ORRI are in the form of net
profits interests ("NPI") equal to a significant percentage of the excess of
gross proceeds over production costs, as defined, from the acquired oil and gas
properties. A net deficit incurred in any month can be carried forward to
subsequent months until such deficit is fully recovered. The Company has the
right to abandon the purchased oil and gas properties if it deems the properties
to be uneconomical.

The Company has, pursuant to the purchase agreements, created abandonment trusts
whereby funds are provided out of gross production proceeds from the properties
for the estimated amount of future abandonment obligations related to the
working interests owned by the Company. The Trusts are administered by unrelated
third party trustees for the benefit of the Company's working interest in each
property. The Trust agreements limit their funds to be disbursed for the
satisfaction of abandonment obligations. Any funds remaining in the Trusts after
all restoration, dismantlement and abandonment obligations have been met will be
distributed to the owners of the properties in the same ratio as contributions
to the Trusts. The Trusts' assets are excluded from the Consolidated Balance
Sheets of the Company because the Company does not control the Trusts. Estimated
future revenues and costs associated with the NPI and the Trusts are also
excluded from the oil and gas reserve disclosures at Note 12. As of December 31,
2002 and 2001, the Trusts' assets (all cash and investments) totaled $6,896,000
and $6,567,000 respectively, all of which will be available to the Company to
pay its portion, as working interest owner, of the restoration, dismantlement
and abandonment costs discussed at Note 7. FAS 143, discussed in Footnote 2,
will require the Abandonment Trusts' assets and the associated abandonment
liability to be recorded in the balance sheet effective January 1, 2003. The
Company does not expect to record any income or loss associated with the Trust
asset or abandonment liability as a result of adoption of FAS 143.

At the time of acquisition of properties by the Company, the property owners
estimated the future costs to be incurred for site restoration, dismantlement
and abandonment, net of salvage value. A portion of the amounts necessary to pay
such estimated costs was deposited in the Trusts upon acquisition of the
properties, and the remainder is deposited from time to time out of the proceeds
from production. The determination of the amount deposited upon the acquisition
of the properties and the amount to be deposited as proceeds from production was
based on numerous factors, including the estimated reserves of the properties.
The amounts deposited in the Trusts upon acquisition of the properties were
capitalized by the Company as oil and gas properties.

As operator, the Company receives all of the revenues and incurs all of the
production costs for the purchased oil and gas properties but retains only that
portion applicable to its net ownership share. As a result, the payables and
receivables associated with operating the properties included in the Company's
Consolidated Balance Sheets include both the Company's and all other outside
owners' shares. However, revenues and production costs associated with the
acquired properties reflected in the accompanying Consolidated Statements of
Operations represent only the Company's share, after reduction for the NPI.

10. EMPLOYEE BENEFIT PLANS

The Company has adopted a series of incentive compensation plans designed to
align the interest of the executives and employees with those of its
stockholders. The following is a brief description of each plan:

The Savings and Protection Plan provides employees with the option to
defer receipt of a portion of their compensation and the Company may,
at its discretion, match a portion of the

54

employee's deferral with cash and Company Common Stock. The Company may
also elect, at its discretion, to contribute a non-matching amount in
cash and Company Common Stock to employees. The amounts held under the
Savings and Protection Plan are invested in various funds maintained by
a third party in accordance with the directions of each employee. An
employee is fully vested, including Company discretionary
contributions, immediately upon participation in the Savings and
Protection Plan. The total amounts contributed by the Company,
including the value of the common stock contributed, were $611,000,
$595,000 and $500,000 in the years 2002, 2001 and 2000, respectively.

The 1994 Stock Incentive Plan (the "1994 Plan"), approved by the
shareholder's in 1994, provides for 600,000 shares of Common Stock to
be reserved for issuance pursuant to such plan. Under the 1994 Plan,
the Company may grant both stock options qualifying under Section 422
of the Internal Revenue Code and options that are not qualified as
incentive stock options, as well as performance shares. These options
have an expiration date 10 years from date of grant.

On August 23, 1996, the Board of Directors of the Company approved and
adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the
"1996 Plan"). The 1996 Plan was approved by the shareholders in 1997
and provides for the same types of awards as the 1994 Plan and is
limited to a maximum of 1,200,000 shares (as amended from the original
900,000 shares) of common stock that may be subject to outstanding
awards. Unvested options are subject to forfeiture upon certain
termination of employment events and expire 10 years from date of
grant.

The Company granted 533,000 stock options to employees on March 23,
2000 and 120,000 stock options to directors on July 25, 2000 at $10.50
per share. The March 23, 2000 grant was subject to shareholder approval
of an amendment to the 1996 Stock Incentive Plan. The amendment, which
was approved on May 9, 2000 at the Annual Meeting of Shareholders,
increased the number of shares reserved for issuance under the 1996
plan to 2,200,000 shares. The excess of the market price over the
exercise price on the approval date of the amendment is amortized over
the three-year vesting period of the options. Compensation costs of
$416,000, $611,000 and $801,000 were recognized in 2002, 2001 and 2000
respectively related to these options.

On February 14, 2002, the Board of Directors of the Company approved
and adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant
to the 2002 Plan, 350,000 shares of common stock shall be reserved for
issuance upon the exercise of options or for grants of stock options,
stock appreciation rights or units, bonus stock, or performance shares
or units. This Plan qualifies as a "broadly based" plan under the
provisions of the New York Stock Exchanges rules and regulations and
therefore did not require shareholder approval. Because the 2002 Plan
is a broadly based plan, the aggregate number of shares underlying
awards granted to officer and directors cannot exceed 50% of the total
number of shares underlying the awards granted to all employees during
any three-year period.

In 2002, the Company awarded 300,000 shares of restricted stock from
the 1996 and the 2002 Plan and 70,500 from treasury shares to be issued
as vested. The issuance of the restricted stock using treasury shares
did not require shareholder approval pursuant to the New York Stock
Exchange's rules and regulations, and therefore shareholder approval
was not sought. These shares will generally vest to the recipients over
a three-year period (one-third in each year)

55

beginning in November 2002. The deferred compensation portion of this
grant will be amortized to expense over the vesting period. The
non-cash amortization expense in 2002 was $496,000.

In 1997, the Board of Directors authorized the implementation of the
Callon Petroleum Company 1997 Employee Stock Purchase Plan (the "1997
Purchase Plan"), which was approved by the Company's shareholders at
the 1997 Annual Meeting. The Plan provides eligible employees of the
Company with the opportunity to acquire a proprietary interest in the
Company through participation in a payroll deduction-based employee
stock purchase plan. An aggregate of 250,000 shares of Common Stock
have been reserved for issuance over the ten-year term of the 1997
Purchase Plan. The purchase price per share at which Common Stock will
be purchased on the participant's behalf on each purchase date within
an offering period is equal to eighty-five percent of the fair market
value per share of Common Stock.

The Company accounts for the options issued pursuant to the stock incentive
plans under APB Opinion No. 25, under which no compensation cost has been
recognized unless the exercise price is less than the market price at the
measurement date. Had compensation cost for these plans been determined
consistent with Statement of Financial Accounting Standards No. 123 ("SFAS
123"), "Accounting for Stock-Based Compensation", the Company's net income and
earnings per common share would have been reduced to the following pro forma
amounts:

56

A summary of the status of the Company's stock option plans for the three most
recent years and changes during the years then ended is presented in the table
and narrative below:

The following table sets forth additional information regarding options
outstanding at December 31, 2002. Contractual life and exercise prices represent
weighted averages for options outstanding and options exercisable.

The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted average
assumptions used for options granted during the years presented are as follows:

11. EQUITY TRANSACTIONS

In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible
Exchangeable Preferred Stock, Series A (the "Preferred Stock") for net proceeds
of $30.9 million. Annual dividends are $2.125 per share and are cumulative. The
net proceeds of the $.01 par value stock after underwriters discount and expense
was $30,899,000. Each share has a liquidation preference of $25.00, plus accrued
and unpaid dividends. Dividends on the Preferred Stock are cumulative from the
date of issuance and are payable quarterly, commencing January 15, 1996. The
Preferred Stock is convertible at any time, at the option of

57

the holders thereof, unless previously redeemed, into shares of Common Stock of
the Company at an initial conversion price of $11 per share of Common Stock,
subject to adjustments under certain conditions.

The Preferred Stock is redeemable at any time on or after December 31, 1998, in
whole or in part at the option of the Company at a redemption price of $26.488
per share beginning at December 31, 1998 and at premiums declining to the $25.00
liquidation preference by the year 2005 and thereafter, plus accrued and unpaid
dividends. The Preferred Stock is also exchangeable, in whole, but not in part,
at the option of the Company on or after January 15, 1998 for the Company's 8.5%
Convertible Subordinated Debentures due 2010 (the "Debentures") at a rate of
$25.00 principal amount of Debentures for each share of Preferred Stock. The
Debentures will be convertible into Common Stock of the Company on the same
terms as the Preferred Stock and will pay interest semi-annually.

In a December 1998 private transaction, a preferred stockholder elected to
convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's
Common Stock. In 1999 certain other preferred stockholders, through private
transactions, agreed to convert 210,350 shares of Preferred Stock into 502,637
shares of the Company's Common Stock under similar terms. Likewise in 2000,
444,600 shares of Preferred Stock were converted into 1,036,098 shares of the
Company's Common Stock. Any non-cash premium negotiated in excess of the
conversion rate was recorded as additional preferred stock dividends and
excluded from the Consolidated Statements of Cash Flows.

In November of 1999, the Company sold 3,680,000 shares of Common Stock in a
public offering at a price to the public of $11.875 per share. Cash proceeds
received by the Company were $41.1 million net of underwriting discount and
offering costs.

In 2001, under the terms of the $95 million multiple advance loans, the Company
issued warrants to purchase, at a nominal exercise price, 265,210 shares of its
common stock. See Note 5.

The Company adopted a stockholder rights plan on March 30, 2000, designed to
assure that the Company's stockholders receive fair and equal treatment in the
event of any proposed takeover of the Company and to guard against partial
tender offers, squeeze-outs, open market accumulations, and other abusive
tactics to gain control without paying all stockholders a fair price. The rights
plan was not adopted in response to any specific takeover proposal. Under the
rights plan, the Company declared a dividend of one right ("Right") on each
share of the Company's Common Stock. Each Right will entitle the holder to
purchase one one-thousandth of a share of a Series B Preferred Stock, par value
$0.01 per share, at an exercise price of $90 per one one-thousandth of a share.

The Rights are not currently exercisable and will become exercisable only in the
event a person or group acquires, or engages in a tender or exchange offer to
acquire, beneficial ownership of 15 percent or more (one existing stockholder
was granted an exception for up to 21 percent) of the Company's Common Stock.
After the Rights become exercisable, each Right will also entitle its holder to
purchase a number of common shares of the Company having a market value of twice
the exercise price. The dividend distribution was made to stockholders of record
at the close of business on April 10, 2000. The Rights will expire on March 30,
2010.

58

12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)

The Company's proved oil and gas reserves at December 31, 2002, 2001 and 2000
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions. These estimates have been adjusted (per SEC
guidelines) to exclude the volumetric production payment described in Note 2.

There are numerous uncertainties inherent in establishing quantities of proved
reserves. The following reserve data represent estimates only and should not be
construed as being exact. In addition, the standard measure of discounted future
net cash flows should not be construed as the current market value of the
Company's oil and gas properties or the cost that would be incurred to obtain
equivalent reserves.

In October 2002, we received a letter from the SEC regarding our Annual Report
on Form 10-K for the year ended December 31, 2001 requesting supplemental
information concerning our operations in the Gulf of Mexico. The comment letters
requested information about the procedures we used to classify our deepwater
reserves as proved and requested that our financials be restated to reflect the
removal of the Boomslang reserves as proved for all prior periods during which
such reserves were reported as proved. We have reviewed the SEC comments with
our independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston,
Texas. Both Huddleston & Co. and Callon believe that such deepwater reserves are
properly classified as proved. If the SEC requires us to retroactively classify
Boomslang as an unproved property through December, 2002, we would be required
to restate our financial position, results of operations, and supplemental oil
and gas reserve data from 1998 through 2002.

59

ESTIMATED RESERVES

Changes in the estimated net quantities of crude oil and natural gas reserves,
all of which are located onshore and offshore in the continental United States,
are as follows:

RESERVE QUANTITIES

STANDARDIZED MEASURE

The following tables present the Company's standardized measure of discounted
future net cash flows and changes therein relating to proved oil and gas
reserves and were computed using reserve valuations based on regulations
prescribed by the SEC. These regulations provide that the oil, condensate and
gas price structure utilized to project future net cash flows reflects current
prices (approximately $4.80 per Mcf for natural gas and $34.22 per Bbl for oil
for the 2002 disclosures, $2.58 per Mcf and $20.10 per Bbl for 2001 disclosures,
and $9.14 per Mcf and $26.71 per Bbl for 2000 disclosures) at each date
presented and have not been escalated. Future production, development and net
abandonment costs are based on current costs

60

without escalation. The resulting net future cash flows have been discounted to
their present values based on a 10% annual discount factor.

STANDARDIZED MEASURE

CHANGES IN STANDARDIZED MEASURE

61

13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

62

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

As reported in our Current Report on Form 8-K dated June 28, 2002, in June 2002,
the Board of Directors of the company approved the engagement of Ernst & Young
LLP as its independent auditors for the fiscal year ending December 31, 2002 to
replace Arthur Andersen LLP, who were dismissed as auditors of the company
effective June 28, 2002. The audit committee of the Board of Directors approved
the change in auditors and recommended this change to the Board of Directors.
The letter of concurrence was filed as an exhibit to the Form 8-K. No
disagreements were cited.

There have been no disagreements with the independent auditors on any matters of
accounting principles or practices, financial statement disclosure, or auditing
scope or procedures.

63

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

For information concerning Item 10, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 2, 2003
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION.

For information concerning Item 11, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 2, 2003
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.

For information concerning the security ownership of certain beneficial owners
and management, see the definitive proxy statement of Callon Petroleum Company
relating to the Annual Meeting of Stockholders on May 2, 2003 which will be
filed with the Securities and Exchange Commission and is incorporated herein by
reference.

64

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information as of December 31, 2002 regarding the
number of shares of Common Stock that may be issued under the Company's equity
compensation plans.

(1) Represents the Callon Petroleum Company 1994 and the 1996 Stock
Incentive Plans which were approved by the shareholders in prior
years. Remaining shares available for future issuance listed in
column (c) does not include 168,000 shares of restricted stock
awarded in 2002 which have not yet vested.

(2) Represents the Callon Petroleum Company 2002 Stock Incentive Plan
adopted by the Company on February 14, 2002. The plan qualifies as
a "broadly based" plan under the provisions of the New York Stock
Exchange rules and regulations and therefore did not require
shareholder approval. Remaining shares available for future
issuance listed in column (c) does not include 124,300 shares of
restricted stock awarded in 2002 which have not yet vested.

See Note 10 to the Consolidated Financial Statements for a description of the
material provisions of each equity compensation plan under which our equity
securities are authorized for issuance that was adopted without the approval of
shareholders.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For information concerning Item 13, see the definitive proxy statement of Callon
Petroleum Company relating to the Annual Meeting of Stockholders on May 2, 2003
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

65

ITEM 14. CONTROLS AND PROCEDURES.

(a) Evaluation of Disclosure Controls and Procedures. Based on their
evaluation as of a date within 90 days of the filing date of this Annual Report
on Form 10-K, the Company's principal executive officer and principal financial
officer have concluded that the Company's disclosure controls and procedures (as
defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of
1934 (the "Exchange Act") are effective to ensure that information required to
be disclosed by the Company in reports that it files or submits under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the Securities and Exchange
Commission.

(b) Changes in Internal Controls. There were no significant changes in
the Company's internal controls or in other factors that could significantly
affect these controls subsequent to the date of their evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.

66

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. The following is an index to the financial statements and financial
statement schedules that are filed as part of this Form 10-K on pages 37 through
63.

Report of Independent Auditors

Consolidated Balance Sheets as of the Years Ended December 31, 2002 and
2001

Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 2002

Consolidated Statements of Stockholders' Equity for the Three Years in
the Period Ended December 31, 2002

Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 2002

Notes to Consolidated Financial Statements

(a) 2. Schedules other than those listed above are omitted because they are not
required, not applicable or the required information is included in the
financial statements or notes thereto.

(a) 3. Exhibits:

2. Plan of acquisition, reorganization, arrangement, liquidation or
succession*

3. Articles of Incorporation and Bylaws

3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the Company's
Registration Statement on Form S-4, filed August 4, 1994, Reg. No.
33-82408)

3.2 Certificate of Merger of Callon Consolidated Partners, L. P. with
and into the Company dated September 16, 1994 (incorporated by
reference from Exhibit 3.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 1994, File No. 000-25192)

3.3 Bylaws of the Company (incorporated by reference from Exhibit 3.2
of the Company's Registration Statement on Form S-4, filed August
4, 1994, Reg. No. 33-82408)

4. Instruments defining the rights of security holders, including
indentures

4.1 Specimen Common Stock Certificate (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed August 4, 1994, Reg. No. 33-82408)

67

4.2 Specimen Preferred Stock Certificate (incorporated by reference
from Exhibit 4.2 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)

4.3 Designation for Convertible, Exchangeable Preferred Stock, Series
A (incorporated by reference from Exhibit 4.3 of the Company's
Registration Statement on Form S-1, filed November 13, 1995, Reg.
No. 33-96700)

4.4 Indenture for Convertible Debentures (incorporated by reference
from Exhibit 4.4 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)

4.5 Certificate of Correction on Designation of Series A Preferred
Stock (incorporated by reference from Exhibit 4.4 of the Company's
Registration Statement on Form S-1, filed November 22, 1996, Reg.
No. 333-15501)

4.6 Indenture for the Company's 10.125% Senior Subordinated Notes due
2002 dated as of July 31, 1997 (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed September 25, 1997, Reg. No. 333-36395)

4.7 Form of Note Indenture for the Company's 10.25% Senior
Subordinated Notes due 2004 (incorporated by reference from
Exhibit 4.10 of the Company's Registration Statement on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)

4.8 Rights Agreement between Callon Petroleum Company and American
Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000
(incorporated by reference from Exhibit 99.1 of the Company's
Registration Statement on Form 8-A, filed April 6, 2000, File No.
001-14039)

4.9 Subordinated Indenture for the Company dated October 26, 2000
(incorporated by reference from Exhibit 4.1 of the Company's
Current Report on Form 8-K dated October 24, 2000, File No.
001-14039)

4.10 Supplemental Indenture for the Company's 11% Senior Subordinated
Notes due 2005 (incorporated by reference from Exhibit 4.2 of the
Company's Current Report on Form 8-K dated October 24, 2000, File
No. 001-14039)

4.11 Warrant dated as of June 29, 2001 entitling Duke Capital Partners,
LLC to purchase common stock from the Company. (incorporated by
reference to Exhibit 4.11 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

4.12 First Supplemental Indenture, dated June 26, 2002, to Indenture
between Callon Petroleum Company and American Stock Transfer &
Trust Company dated July 31, 1997. (incorporated by reference to
Exhibit 4.1 of the Company's Current Report on Form 8-K dated June
26, 2002, File No. 001-14039)

4.13 Form of Warrant entitling certain holders of the Company's 10.125%
Senior Subordinated Notes due 2002 to purchase common stock from
the Company (incorporated by reference to

68

Exhibit 4.13 of the Company's Form 10-Q for the period ended
June 30, 2002, File No. 001- 14039)

4.14 Second Supplemental Indenture, dated September 16, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on Form
8-K dated September 16, 2002, File No. 001-14039)

9. Voting trust agreement

None.

10. Material contracts

10.1 Registration Rights Agreement dated September 16, 1994 between the
Company and NOCO Enterprises, L. P. (incorporated by reference
from Exhibit 10.2 of the Company's Registration Statement on Form
8-B filed October 3, 1994)

10.2 Counterpart to Registration Rights Agreement by and between the
Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
reference from Exhibit 10.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 2000, File No. 001-14039)

10.3 Registration Rights Agreement dated September 16, 1994 between the
Company and Callon Stockholders (incorporated by reference from
Exhibit 10.3 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)

10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated
by reference from Exhibit 10.5 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)

10.5 Consulting Agreement between the Company and John S. Callon dated
June 19, 1996 (incorporated by reference from Exhibit 10.10 of the
Company's Registration Statement on Form S-1, filed November 5,
1996, Reg. No. 333-15501)

10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the Post-Effective
Amendment No. 1 to the Company's Registration Statement on Form
S-8, filed February 5, 1999, Reg No. 333-29537)

10.7 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2, filed
June 14, 1999, Reg. No. 333-80579)

10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended on
May 9, 2000 (incorporated by reference from Appendix I of the
Company's Definitive Proxy Statement of Schedule 14A filed March
28, 2000)

69

10.9 Credit Agreement dated as of October 30, 2000 between the Company
and First Union National Bank, as administrative agent for the
lenders (incorporated by reference from Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the period ended
September 30, 2000, File No. 001-14039)

10.10 Credit Agreement dated as of June 29, 2001 between the Company and
Duke Capital Partners, LLC, as Administrative Agent (incorporated
by reference to Exhibit 10.01 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

10.11 Second Amendment to Credit Agreement by and among the Company and
First Union National Bank, as Administrative Agent, effective as
of June 29, 2001 (incorporated by reference to Exhibit 10.01 of
the Company's Quarterly Report on Form 10-Q for the period ended
June 30, 2001, File No. 001-14039)

10.12 Conveyance of Overriding Royalty Interest from the Company to Duke
Capital Partners, LLC, dated June 29, 2001 (incorporated by
reference to Exhibit 10.03 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

10.13 Callon Petroleum Company 2002 Stock Incentive Plan (incorporated
by reference to Exhibit 10.13 of the Company's Annual Report on
Form 10-K for the year ended December 31, 2001, File No.
001-14039).

10.14 Change of Control Severance Compensation Agreement by and between
Callon Petroleum and John S. Weatherly dated January 1, 2002
(incorporated by reference to Exhibit 10.14 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)

10.15 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Fred L. Callon, dated January 1, 2002
(incorporated by reference to Exhibit 10.15 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)

10.16 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Dennis W. Christian, dated January 1,
2002 (incorporated by reference to Exhibit 10.16 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)

10.17 First Amended and Restated Credit Agreement dated as of June 30,
2002, among Callon Petroleum Company, each of the lenders that is
a signatory thereto, Wachovia Bank National Association, as
administrative agent, and Union Bank of California, N.A., as
documentation agent (incorporated by reference to Exhibit 10.1 of
the Company's Form 10-Q for the period ended June 30, 2002, File
No. 001-14039)

11. Statement re computation of per share earnings*

12. Statements re computation of ratios*

70

13. Annual Report to security holders, Form 10-Q or quarterly reports*

16. Letter re change in certifying accountant*

18. Letter re change in accounting principles*

21. Subsidiaries of the Company

21.1 Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)

22. Published report regarding matters submitted to vote of security
holders*

23. Consents of experts and counsel

23.1 Consent of Ernst & Young LLP

24. Power of attorney*

99. Additional Exhibits

99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

- ----------------------------
*Inapplicable to this filing.

(b) Reports on Form 8-K.

Current Report dated June 26, 2002, reporting Item 5. Other Events

Current Report dated June 28, 2002, reporting Item 4. Change in Registrant's
Certifying Accounts

Current Report dated August 14, 2002, reporting Item 9. Regulation FD
Disclosure

Current Report dated September 16, 2002, reporting Item 5. Other Events

Current Report dated October 1, 2002, reporting Item 9. Regulation FD
Disclosure

Current Report dated December 12, 2002, reporting Item 9. Regulation FD
Disclosure

71

SIGNATURES

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.

CALLON PETROLEUM COMPANY

Date: March 27, 2003 /s/ Fred L. Callon
-------------- ------------------------------------------------------
Fred L. Callon (principal executive officer, director)

Date: March 27, 2003 /s/ John S. Weatherly
-------------- ------------------------------------------------------
John S. Weatherly (principal financial officer)

Date: March 27, 2003 /s/ James O. Bassi
-------------- -------------------------------------------------------
James O. Bassi (principal accounting officer)

Date: March 27, 2003 /s/John S. Callon
-------------- ------------------------------------------------------
John S. Callon (director)

Date: March 27, 2003 /s/Dennis W. Christian
-------------- ------------------------------------------------------
Dennis W. Christian (director)

Date: March 27, 2003 /s/B. F. Weatherly
-------------- ------------------------------------------------------
B. F. Weatherly (director)

Date: March 27, 2003 /s/Robert A. Stanger
-------------- -------------------------------------------------------
Robert A. Stanger (director)

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.

CALLON PETROLEUM COMPANY

Date: March 27, 2003 By: /s/ John S. Weatherly
----------------------------------------------
John S. Weatherly, Senior Vice President and
Chief Financial Officer

72

CERTIFICATIONS

I, Fred L. Callon, certify that:

1. I have reviewed this annual report on Form 10-K of Callon Petroleum
Company;

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;

(b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and

(c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: March 27, 2003
By: /s/ Fred L. Callon
-------------------------------------------------------
Fred L. Callon, President and Chief Executive Officer
(Principal Executive Officer)

73

CERTIFICATIONS

I, John S. Weatherly, certify that:

2. Based on my knowledge, this annual report does not contain any
untrue statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report is
being prepared;

(b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and

(c) Presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

(a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

(b) Any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

Date: March 27, 2003
By: /s/ John S. Weatherly
---------------------------------------------------------
John S. Weatherly, Senior Vice President
and Chief Financial Officer (Principal Financial Officer)

74

EXHIBIT INDEX

2. Plan of acquisition, reorganization, arrangement, liquidation or
succession*

3. Articles of Incorporation and Bylaws

3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the Company's
Registration Statement on Form S-4, filed August 4, 1994, Reg. No.
33-82408)

3.2 Certificate of Merger of Callon Consolidated Partners, L. P. with
and into the Company dated September 16, 1994 (incorporated by
reference from Exhibit 3.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 1994, File No. 000-25192)

3.3 Bylaws of the Company (incorporated by reference from Exhibit 3.2
of the Company's Registration Statement on Form S-4, filed August
4, 1994, Reg. No. 33-82408)

4. Instruments defining the rights of security holders, including
indentures

4.1 Specimen Common Stock Certificate (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed August 4, 1994, Reg. No. 33-82408)

4.2 Specimen Preferred Stock Certificate (incorporated by reference
from Exhibit 4.2 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)

4.3 Designation for Convertible, Exchangeable Preferred Stock, Series
A (incorporated by reference from Exhibit 4.3 of the Company's
Registration Statement on Form S-1, filed November 13, 1995, Reg.
No. 33-96700)

4.4 Indenture for Convertible Debentures (incorporated by reference
from Exhibit 4.4 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)

4.5 Certificate of Correction on Designation of Series A Preferred
Stock (incorporated by reference from Exhibit 4.4 of the Company's
Registration Statement on Form S-1, filed November 22, 1996, Reg.
No. 333-15501)

4.6 Indenture for the Company's 10.125% Senior Subordinated Notes due
2002 dated as of July 31, 1997 (incorporated by reference from
Exhibit 4.1 of the Company's Registration Statement on Form S-4,
filed September 25, 1997, Reg. No. 333-36395)

4.7 Form of Note Indenture for the Company's 10.25% Senior
Subordinated Notes due 2004 (incorporated by reference from
Exhibit 4.10 of the Company's Registration Statement on Form S-2,
filed June 14, 1999, Reg. No. 333-80579)

4.8 Rights Agreement between Callon Petroleum Company and American
Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000
(incorporated by reference from Exhibit 99.1 of the Company's
Registration Statement on Form 8-A, filed April 6, 2000, File No.
001-14039)

4.9 Subordinated Indenture for the Company dated October 26, 2000
(incorporated by reference from Exhibit 4.1 of the Company's
Current Report on Form 8-K dated October 24, 2000, File No.
001-14039)

4.10 Supplemental Indenture for the Company's 11% Senior Subordinated
Notes due 2005 (incorporated by reference from Exhibit 4.2 of the
Company's Current Report on Form 8-K dated October 24, 2000, File
No. 001-14039)

4.11 Warrant dated as of June 29, 2001 entitling Duke Capital Partners,
LLC to purchase common stock from the Company. (incorporated by
reference to Exhibit 4.11 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

4.12 First Supplemental Indenture, dated June 26, 2002, to Indenture
between Callon Petroleum Company and American Stock Transfer &
Trust Company dated July 31, 1997. (incorporated by reference to
Exhibit 4.1 of the Company's Current Report on Form 8-K dated June
26, 2002, File No. 001-14039)

4.13 Form of Warrant entitling certain holders of the Company's 10.125%
Senior Subordinated Notes due 2002 to purchase common stock from
the Company (incorporated by reference to Exhibit 4.13 of the
Company's Form 10-Q for the period ended June 30, 2002, File No.
001- 14039)

4.14 Second Supplemental Indenture, dated September 16, 2002, to
Indenture between Callon Petroleum Company and American Stock
Transfer & Trust Company dated July 31, 1997. (incorporated by
reference to Exhibit 4.1 of the Company's Current Report on Form
8-K dated September 16, 2002, File No. 001-14039)

9. Voting trust agreement

None.

10. Material contracts

10.1 Registration Rights Agreement dated September 16, 1994 between the
Company and NOCO Enterprises, L. P. (incorporated by reference
from Exhibit 10.2 of the Company's Registration Statement on Form
8-B filed October 3, 1994)

10.2 Counterpart to Registration Rights Agreement by and between the
Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by
reference from Exhibit 10.2 of the Company's Report on Form 10-K
for the fiscal year ended December 31, 2000, File No. 001-14039)

10.3 Registration Rights Agreement dated September 16, 1994 between the
Company and Callon Stockholders (incorporated by reference from
Exhibit 10.3 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)

10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated
by reference from Exhibit 10.5 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)

10.5 Consulting Agreement between the Company and John S. Callon dated
June 19, 1996 (incorporated by reference from Exhibit 10.10 of the
Company's Registration Statement on Form S-1, filed November 5,
1996, Reg. No. 333-15501)

10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the Post-Effective
Amendment No. 1 to the Company's Registration Statement on Form
S-8, filed February 5, 1999, Reg No. 333-29537)

10.7 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2, filed
June 14, 1999, Reg. No. 333-80579)

10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended on
May 9, 2000 (incorporated by reference from Appendix I of the
Company's Definitive Proxy Statement of Schedule 14A filed March
28, 2000)

10.9 Credit Agreement dated as of October 30, 2000 between the Company
and First Union National Bank, as administrative agent for the
lenders (incorporated by reference from Exhibit 10.2 of the
Company's Quarterly Report on Form 10-Q for the period ended
September 30, 2000, File No. 001-14039)

10.10 Credit Agreement dated as of June 29, 2001 between the Company and
Duke Capital Partners, LLC, as Administrative Agent (incorporated
by reference to Exhibit 10.01 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

10.11 Second Amendment to Credit Agreement by and among the Company and
First Union National Bank, as Administrative Agent, effective as
of June 29, 2001 (incorporated by reference to Exhibit 10.01 of
the Company's Quarterly Report on Form 10-Q for the period ended
June 30, 2001, File No. 001-14039)

10.12 Conveyance of Overriding Royalty Interest from the Company to Duke
Capital Partners, LLC, dated June 29, 2001 (incorporated by
reference to Exhibit 10.03 of the Company's Quarterly Report on
Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

10.13 Callon Petroleum Company 2002 Stock Incentive Plan (incorporated
by reference to Exhibit 10.13 of the Company's Annual Report on
Form 10-K for the year ended December 31, 2001, File No.
001-14039).

10.14 Change of Control Severance Compensation Agreement by and between
Callon Petroleum and John S. Weatherly dated January 1, 2002
(incorporated by reference to Exhibit 10.14 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)

10.15 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Fred L. Callon, dated January 1, 2002
(incorporated by reference to Exhibit 10.15 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)

10.16 Change of Control Severance Compensation Agreement by and between
Callon Petroleum Company and Dennis W. Christian, dated January 1,
2002 (incorporated by reference to Exhibit 10.16 of the Company's
Annual Report on Form 10-K for the year ended December 31, 2001,
File No. 001-14039)

10.17 First Amended and Restated Credit Agreement dated as of June 30,
2002, among Callon Petroleum Company, each of the lenders that is
a signatory thereto, Wachovia Bank National Association, as
administrative agent, and Union Bank of California, N.A., as
documentation agent (incorporated by reference to Exhibit 10.1 of
the Company's Form 10-Q for the period ended June 30, 2002, File
No. 001-14039)

11. Statement re computation of per share earnings*

12. Statements re computation of ratios*

13. Annual Report to security holders, Form 10-Q or quarterly reports*

16. Letter re change in certifying accountant*

18. Letter re change in accounting principles*

21. Subsidiaries of the Company

21.1 Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)

22. Published report regarding matters submitted to vote of security
holders*

23. Consents of experts and counsel

23.1 Consent of Ernst & Young LLP

24. Power of attorney*

99. Additional Exhibits

99.1 Certification of Chief Executive Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

99.2 Certification of Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

- ----------------------------
*Inapplicable to this filing.