CALLON PETROLEUM CO, 424B4, 1999-07-15

CALLON PETROLEUM CO
424B4, 1999-07-15
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

FILED PURSUANT TO RULE 424(B)(4)
REGISTRATION NO. 333-80579

$40,000,000

CALLON PETROLEUM COMPANY
[CALLON PETROLEUM COMPANY LOGO]

10.25% SENIOR SUBORDINATED NOTES DUE 2004
------------------------
INVESTING IN THE NOTES INVOLVES RISKS.
SEE "RISK FACTORS" BEGINNING ON PAGE 9.
------------------------
TERMS OF NOTES

- - MATURITY
September 15, 2004.

- - INTEREST
Fixed annual rate of 10.25%.

We will pay interest on the notes on March 15, June 15, September 15 and
December 15 of each year. The first interest payment will be made on September
15, 1999, which will represent interest accrued from July 20, 1999.

- - TRADING
The notes have been approved for listing on the New York Stock Exchange under
the symbol "CPE 04."

- - OPTIONAL REDEMPTION
We may redeem the notes at any time on or after March 15, 2001 at 100% of
their principal amount plus accrued and unpaid interest.

- - RANKING
The notes are subordinated in right of payment to all of our senior debt and
to the obligations of our subsidiaries. The notes rank equally with our
existing and future senior subordinated indebtedness. The notes are senior to
our outstanding preferred stock.

- - CHANGE OF CONTROL
If a change of control occurs, we must offer to repurchase the notes at 101%
of their principal amount plus accrued and unpaid interest.

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

<TABLE>
<CAPTION>
PER NOTE TOTAL
------------------- -------------------
<S> <C> <C>
Public offering price....................................... 100.0% $40,000,000
Underwriting discount....................................... 3.5% $ 1,400,000
Proceeds, before expenses................................... 96.5% $38,600,000
</TABLE>

The underwriters expect to deliver the notes in book-entry form only
through the facilities of The Depository Trust Company against payment in New
York, New York on July 20, 1999.

Neither the Securities and Exchange Commission nor any state securities
regulators have approved or disapproved these securities, or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.
------------------------

A.G. EDWARDS & SONS, INC. MORGAN KEEGAN & COMPANY, INC.

Prospectus dated July 14, 1999
<PAGE> 2
[MAP SHOWING PRINCIPAL AREAS OF OPERATIONS IN THE GULF OF MEXICO.
MAP DIVIDES THE GULF INTO THE SHALLOW MIOCENE AREA, OCS AREA AND
DEEP WATER AREA.]

CORPORATE PROFILE

- Geographic concentration in the Gulf of Mexico.

- Estimated net proved reserves of 183.3 Bcfe with a discounted present value
of $173.9 million as of June 1, 1999.

- Average daily net production of 43.4 MMcfe during the first quarter of 1999,
86% of which was natural gas.

- Reserve life of 12.1 years.

215% RESERVE GROWTH

- Between January 1, 1996 and June 1, 1999, estimated net proved reserves
increased 215% from 58.3 Bcfe to 183.3 Bcfe.

SIGNIFICANT DEEP WATER SUCCESS

- In September 1998, we announced a discovery on our Boomslang prospect, and
in February 1999, we announced a discovery on our Habanero prospect.

- These discoveries represent the largest discoveries in our history and have
added estimated net proved reserves of 86.8 Bcfe at a cost to us of $10.2
million to drill.

SUBSTANTIAL INVENTORY OF PROSPECTS

- We currently have an inventory of 39 exploratory prospects, all of which
have been defined by seismic data and interpretation.

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<PAGE> 3

PROSPECTUS SUMMARY

This summary highlights selected information from this document but does
not contain all of the information you need to consider in making your
investment decision. To understand all of the terms of this offering and for a
more complete understanding of our business, you should carefully read this
entire document and the documents incorporated by reference in this document,
particularly the section entitled "Risk Factors." When we use the terms
"Callon," "we," "us" or "our," we are referring to Callon Petroleum Company
together with its consolidated subsidiaries and predecessors, unless the context
otherwise requires. If you are not familiar with the ownership of oil and gas
properties or the way in which quantities and values of oil and gas reserves are
described, please read "Glossary of Oil and Gas Terms" included in this
document.

THE COMPANY

Callon has been engaged in the exploration, development, acquisition and
production of oil and gas in the Gulf Coast region since 1950. Our properties
and operations are geographically concentrated in the offshore waters of the
Gulf of Mexico where we have substantial experience. As of June 1, 1999, we had
estimated net proved reserves of 183.3 Bcfe which had a discounted present value
of $173.9 million. Reserves comprising 72% of this discounted present value were
classified as proved developed. Average daily net production during the first
quarter of 1999 was 43.4 MMcfe, of which 86% was natural gas. We operate wells
representing 82% of this production. Net proved reserves as of June 1, 1999
divided by our production from the four quarters ended March 31, 1999, sometimes
referred to as our "reserve life," was 12.1 years.

Our reserves and production have grown rapidly since 1996 as a result of
exploration and development drilling, as well as property acquisitions. Between
January 1, 1996 and June 1, 1999, estimated net proved reserves increased 215%,
and average daily net production increased 70% from the first quarter of 1996 to
the first quarter of 1999.

BUSINESS STRATEGY

Our goals are to increase reserves, production, cash flow and earnings at
low reserve replacement costs. We seek to achieve these goals through the
following strategies:

- Assemble and explore a balanced portfolio of projects in the Gulf of
Mexico composed of:

Controlling working interests in projects with low exploration risk and
low drilling and completion costs targeting reserve deposits of between
3 and 10 Bcf in the shallow Miocene area at depths of less than 4,000
feet;

Significant working interests in projects with higher exploration risk
and higher drilling and completion costs targeting reserve deposits of
between 10 and 100 Bcfe in the outer continental shelf ("OCS") area at
depths of between 7,000 and 17,000 feet; and

Small working interests in projects with high exploration risk and high
drilling and completion costs targeting large reserve deposits in the
deep water area of the Gulf of Mexico.

- Acquire at low costs, additional working interests, gathering systems,
pipelines, production facilities and other infrastructure in areas in
which we operate. Ownership of these facilities enables us to reduce the
costs of completing wells and to control the timing of the development of
our properties.

- Utilize the latest available technology. Our geoscientists and petroleum
engineers have developed an expertise with advanced technologies,
including 3-D seismic interpretation and computer-aided exploration. In
addition, we have developed a proprietary, inexpensive, high-resolution
2-D seismic data processing and interpretation technique to target
shallow Miocene formations.

- Maintain financial flexibility. We seek to maintain a substantial unused
borrowing capacity under our bank credit facility by periodically
refinancing our bank debt in the capital markets by issuing both debt and
equity securities.

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EXPLORATION OPERATIONS

We explore for oil and gas in the state and federal waters of the Gulf of
Mexico. Since 1996, we have drilled nine gross (5.3 net) productive exploration
wells and nine gross (3.4 net) dry holes in the Gulf of Mexico for a gross
success rate of 50% (61% net). We have also drilled five gross (2.9 net)
development wells in the Gulf of Mexico, all of which were successful. We
currently have one gross (0.9 net) exploration well in the OCS area in progress,
and have an inventory of 39 exploration prospects. Our principal areas of
exploration are summarized below. For a more complete description see "Business
and Properties."

Shallow Miocene Area. In the shallow Miocene area, we explore for gas
deposits using 3-D and conventional 2-D seismic technology, as well as a
proprietary high-resolution 2-D seismic data processing and interpretation
technique which better defines reservoir thickness and continuity. We have an
average working interest in productive wells in the shallow Miocene area of 83%,
all of which we operate. Since 1996, we have drilled three gross (2.7 net)
exploration wells, of which two gross (2.0 net) were productive, and two gross
(1.5 net) development wells, both of which were productive. Our drilling
activities in the shallow Miocene area have added 11.2 Bcf of estimated net
proved reserves at a cost to us of $9.5 million to drill and complete. We have
acquired an extensive infrastructure of production platforms, gathering systems
and pipelines located in our shallow Miocene area. These facilities reduce the
development costs of our successful wells and reduce the time necessary to begin
production from successful wells. In 1997, we also acquired 52.5 Bcf of
estimated net proved reserves in the Mobile Block 864 area for a total
acquisition cost of $48.7 million. As described under "Recent Developments," we
have acquired additional interests in this area. We currently have an inventory
of four exploration prospects in this area, two of which we expect to drill
before year-end 1999.

Outer Continental Shelf Area. We explore for oil and gas deposits in the
OCS area of the Gulf of Mexico using the latest in 3-D seismic technology. The
wells drilled in this area are more expensive than the shallow Miocene wells and
target larger oil and gas deposits. Our weighted average working interest in
productive wells in the OCS area is 65.4%. Since 1996, we have added 28.6 Bcfe
of estimated net proved reserves at a cost to us of $28.3 million to drill and
complete. Since 1996, we have drilled 13 gross (5.5 net) exploration wells in
this area, of which five gross (2.8 net) were productive, and we currently have
one gross (0.9 net) exploration well in progress. We also drilled three gross
(1.4 net) development wells, all of which were successful. We currently have an
inventory of 20 exploration prospects in this area, nine of which we expect to
drill before year-end 2000.

Deep Water Area. We allocate a portion of our capital expenditure budget to
the exploration of deep water regions in the Gulf of Mexico. These wells are
expensive to drill and complete and target large reserve deposits. These wells
are usually located far from production facilities and may require long lead
times to construct pipelines and other facilities necessary to begin production.
To reduce the risks associated with the high cost of these wells, we explore
these prospects with experienced joint venture partners, including Shell
Deepwater Development, Inc. and Murphy Exploration and Production, Inc., as
operators. We have drilled two wells in our deep water area, both of which were
successful. In September 1998, we announced a discovery on our "Boomslang"
prospect, and in February 1999, we announced a discovery on our "Habanero"
prospect. These discoveries represent the largest discoveries in our history and
have added estimated net proved reserves of 86.8 Bcfe at a cost to us of $10.2
million to drill. Costs to complete these wells cannot be determined until we
drill several related prospects. We currently have an inventory of 15 deep water
exploration prospects, four of which we expect to drill before year-end 2000.

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<PAGE> 5

RECENT DEVELOPMENTS

On June 11, 1999, we acquired Murphy's working interests in nine blocks in
the shallow Miocene area in which we already owned an interest. Included in the
acquisition is a 13.1% working interest in four producing wells in the Mobile
Block 864 unit and a 38.6% average working interest in three additional
producing wells. Murphy will receive a production payment entitling it to 7.6
Bcf of gas from production attributable to the wells over three and a quarter
years. Through this acquisition, we also gained control over exploration of
58,000 gross acres. After giving effect to the acquisition as if it had occurred
on January 1, 1999, our average daily net production would have increased by 5.3
MMcf, or 12.2%, during the first quarter of 1999.

In February 1999, we announced a discovery on our Habanero prospect in the
deep water area. This well was drilled in 2,000 feet of water to a total
measured depth of 21,158 feet. We have an 11.3% working interest in this well,
which had estimated net proved reserves as of June 1, 1999 of 50.9 Bcfe.

In January 1999, we announced a discovery on our Snapper prospect in the
OCS area. This well was drilled in 210 feet of water to a total measured depth
of 8,800 feet. We have a 50.0% working interest in this well, which had 5.0 Bcfe
of estimated net proved reserves as of June 1, 1999.

In September 1998, we announced a discovery on our Boomslang prospect in
the deep water area. This well was drilled in 900 feet of water to a total
measured depth of 13,200 feet. We have a 35.0% working interest in this well,
which had estimated net proved reserves as of June 1, 1999 of 35.9 Bcfe.

SIGNIFICANT PROPERTIES

The following table provides information about estimated net proved
reserves attributable to our principal operating areas as of June 1, 1999.
Estimated net quantities of proved oil and gas reserves and the discounted
present value of the reserves were estimated by our independent reserve
engineers.

<TABLE>
<CAPTION>
ESTIMATED NET PROVED RESERVES PERCENT
------------------------------ DISCOUNTED TOTAL
GAS OIL TOTAL PRESENT VALUE DISCOUNTED
(MMCF) (MBBLS) (MMCFE) ($000) PRESENT VALUE
-------- -------- -------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Shallow Miocene area................... 57,906 -- 57,906 $ 71,135 40.9%
OCS area............................... 20,839 951 26,546 38,156 21.9%
Deep water area........................ 20,829 10,994 86,791 48,987 28.2%
Other areas............................ 5,399 1,106 12,034 15,639 9.0%
------- ------ ------- -------- -----
Total........................ 104,973 13,051 183,277 $173,917 100.0%
======= ====== ======= ======== =====
</TABLE>

PRINCIPAL OFFICE

Our principal executive offices are located at 200 North Canal Street,
Natchez, Mississippi 39120 and our telephone number is (601) 442-1601.

5
<PAGE> 6

THE OFFERING

Securities Offered......... $40,000,000 principal amount of 10.25% Senior
Subordinated Notes due 2004.

Maturity................... September 15, 2004.

Interest Payment Dates..... March 15, June 15, September 15 and December 15.
The first interest payment will be September 15,
1999, which will represent interest accrued from
July 20, 1999.

Optional Redemption........ On or after March 15, 2001, we may redeem all or a
portion of the notes at 100% of their principal
amount plus accrued and unpaid interest.

Ranking.................... The notes:

- are unsecured;

- rank junior to our current and future senior
debt, including debt we may incur under our bank
credit facility, and the liabilities of our
subsidiaries;

- rank equally with our existing and future senior
subordinated debt; and

- are senior to our outstanding preferred stock.

Assuming we had issued the notes and applied the
proceeds as intended as of March 31, 1999, we would
have had no senior indebtedness and $100.2 million
of senior subordinated indebtedness, including the
notes. Also, our subsidiaries had $12.0 million of
liabilities on their balance sheets at March 31,
1999, excluding guaranties of our bank debt.

Restrictive Covenants...... The indenture governing the notes will, among other
things, limit our ability and the ability of our
subsidiaries to:

- incur additional indebtedness;

- place liens on our assets;

- make dividend payments on our common stock or
repurchase any of our capital stock;

- enter into affiliate transactions; and

- merge, consolidate and sell substantially all of
our assets.

The covenants are fully described under
"Description of the Notes -- Certain Covenants."

Change of Control.......... If a change of control occurs, we must offer to
repurchase the notes at 101% of their principal
amount plus accrued and unpaid interest. For a
description of the change of control provisions,
see "Description of the Notes -- Certain
Covenants -- Change of Control."

Use of Proceeds............ The net proceeds we receive from the sale of the
notes, together with our cash flows and borrowings
under our bank credit facility, will be used to
fund our remaining 1999 capital expenditure budget
and a portion of our 2000 capital expenditure
budget. Pending this use of the net proceeds, we
will repay amounts under our bank credit facility,
which may be reborrowed at a later date.

Trading.................... The notes have been approved for listing on the New
York Stock Exchange under the symbol "CPE 04."

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<PAGE> 7

SUMMARY FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)

The following is our summary financial data. For further information that
will help you better understand the summary data, see "Selected Financial Data."

STATEMENT OF CASH FLOWS DATA:
Cash provided by operating activities... $ 2,965 $ 9,147 $ 29,721 $ 27,337 $ 14,323
Cash used in investing activities....... 13,730 12,397 54,196 85,159 36,063
Cash provided by (used in) financing
activities............................ 8,615 (673) 15,178 65,750 25,144

BALANCE SHEET DATA (END OF PERIOD):
Working capital......................... $ 576 $ 7,880 $ 1,142 $ 12,719 $ 4,878
Oil and gas properties, net............. 151,963 111,213 141,905 150,494 82,489
Total assets............................ 188,457 191,615 181,652 190,421 118,520
Total debt.............................. 92,231 60,250 81,250 60,250 24,250
Stockholders' equity.................... 82,730 114,788 84,484 113,701 77,864

OTHER FINANCIAL DATA:
Capital expenditures, net............... $ 13,730 $ 12,397 $ 54,196 $ 85,159 $ 36,063
EBITDA.................................. $ 6,116 $ 8,974 $ 27,564 $ 33,209 $ 16,138
Ratio of EBITDA to interest expense..... 10.7x 12.9x 14.3x 17.0x 51.6x
Ratio of earnings to fixed charges...... -- 1.7x -- 3.3x 8.8x
Ratio of total debt to EBITDA........... 3.7x 1.9x 2.9x 1.8x 1.5x
</TABLE>

7
<PAGE> 8

SUMMARY OPERATING AND RESERVE DATA

The following is our summary operating and reserve data. For further
information that will help you better understand the summary data, see "Selected
Financial Data."

<TABLE>
<CAPTION>
THREE MONTHS
ENDED
MARCH 31, YEARS ENDED DECEMBER 31,
--------------- --------------------------
1999 1998 1998 1997 1996
------ ------ ------- ------- ------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls)..................................... 90 112 310 462 585
Gas (MMcf)...................................... 3,369 4,036 14,036 13,114 6,269
Total production (MMcfe)........................ 3,909 4,706 15,894 15,887 9,781

AVERAGE SALES PRICE:
Oil (per Bbl)................................... $11.49 $13.85 $ 12.41 $ 18.63 $18.27
Gas (per Mcf)................................... 2.06 2.35 2.26 2.56 2.40
Total production (per Mcfe)..................... 2.04 2.35 2.24 2.65 2.63

AVERAGE COSTS (PER MCFE):
Lease operating expenses (excluding severance
taxes)........................................ $ .35 $ .34 $ .44 $ .42 $ .57
Severance taxes................................. .06 .07 .06 .09 .20
Depreciation, depletion and amortization........ 1.01 1.18 1.19 1.04 1.01
General and administrative (net of management fees)... .27 .32 .33 .28 .36
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 1, ------------------------------
1999 1998 1997 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C>
ESTIMATED NET PROVED RESERVES:
Oil (MBbls)........................................ 13,051 6,898 3,402 3,819
Gas (MMcf)......................................... 104,973 88,030 88,738 50,424
Gas equivalent (MMcfe)............................. 183,277 129,418 109,150 73,338
Estimated future net cash flows before income taxes
(000s)........................................... $280,980 $152,552 $209,260 $216,154
Discounted present value (000s).................... $173,917 $ 99,751 $136,448 $160,171

OTHER RESERVE DATA:
Reserve replacement costs ($/Mcfe)................. $ .58 $ 1.29 $ 1.45 $ .73
Reserve life (years)............................... 12.1 8.1 6.9 7.5
</TABLE>

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RISK FACTORS

You should carefully consider all of the information we have included in
this document and the documents we have included or incorporated by reference
before purchasing our notes.

OUR SIGNIFICANT DEBT LEVELS AND OUR DEBT COVENANTS MAY LIMIT OUR FUTURE
FLEXIBILITY IN OBTAINING ADDITIONAL FINANCING AND IN PURSUING BUSINESS
OPPORTUNITIES.

Assuming we had issued the notes and applied the proceeds as described in
"Use of Proceeds" as of March 31, 1999, we would have had approximately $100.2
million in long-term debt. The level of our indebtedness will have important
effects on our future operations, including:

- A portion of our cash flow will be used to pay interest and principal on
our debt and will not be available for other purposes.

- Our bank credit facility contains financial tests which we must satisfy
in order to continue to borrow funds under the facility. Failure to meet
these tests may be a default under our bank credit facility.

- Covenants in the notes and in our existing senior subordinated notes
require us to meet financial tests in order to borrow additional money,
which may have the effect of limiting our flexibility in reacting to
changes in our business and our ability to fund future operations and
acquisitions.

- Our ability to obtain additional financing for capital expenditures and
other purposes may be limited.

We have included a more thorough discussion of the covenants in our bank
credit facility and existing senior subordinated notes under "Description of
Bank Credit Facility and Other Indebtedness."

THERE MAY NOT BE SUFFICIENT ASSETS TO PAY AMOUNTS OWED ON THE NOTES IF A DEFAULT
OCCURS.

The notes will be subordinated to our current and future senior debt. In
addition, the notes will rank equally with our existing and future senior
subordinated indebtedness and will be subordinated to the obligations of our
subsidiaries. Upon a liquidation or in a bankruptcy or other similar proceeding,
the holders of our senior debt will be entitled to be paid in full before any
payment may be made to the holders of the notes. In addition, creditors of our
subsidiaries will be paid prior to any use of our subsidiaries' assets to make
payments on the notes. As a result, the holders of notes may receive less,
proportionately, than the holders of senior debt. We cannot make any assurances
that we will have sufficient assets to pay amounts due on the notes. Our
indenture for the notes permits us to incur additional debt in the future,
including the entire amount that will be available for borrowing under our bank
credit facility.

THERE MAY NOT BE A LIQUID MARKET FOR RESALE OF THE NOTES.

The notes will be new securities for which currently there is no trading
market. Even though the notes have been approved for listing on the New York
Stock Exchange, we cannot assure you that a market for the notes will develop,
or that the market will have sufficient liquidity to enable resale of the notes.

WE MAY NOT BE ABLE TO REPURCHASE NOTES UPON A CHANGE OF CONTROL.

If a change of control occurs, each holder of the notes will have the right
to require us to repurchase all or any part of that holder's notes as described
under "Description of the Notes -- Certain Covenants -- Change of Control." Our
bank credit facility prohibits the repurchase of the notes. In order to
repurchase the notes, we would be required to repay our debt under our bank
credit facility or obtain consents from our bank lenders. If we cannot repay the
bank credit facility or obtain the consents, we would not be able to repurchase
the notes. Also, we may not have sufficient funds available or be able to obtain
the financing necessary to repurchase the notes.

If a change of control occurs and we do not offer to repurchase the notes
or if we do not repurchase the notes when we are required to, an event of
default will occur under the indenture governing the notes,
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<PAGE> 10

which would also be a default under our bank credit facility and other senior
subordinated notes. Each of these defaults could have a material adverse effect
on us and the holders of the notes.

OIL AND GAS PRICES ARE VOLATILE AND HAVE BEEN DEPRESSED RECENTLY.

Our success is highly dependent on prices for oil and gas, which are
extremely volatile. Beginning in 1997 and continuing through earlier this year,
the prices we received for our production generally declined, especially for
oil. Oil prices have recently recovered, but remain low by historic standards.
Any additional 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 government actions. Prices of oil and gas will
affect the following aspects of our business:

- our revenues, cash flows and earnings;

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

- the amount we are allowed to borrow under our bank credit facility;

- the value of our oil and gas properties; and

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

WE MAY BE UNABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED.

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
in the Gulf Coast region, our producing properties usually have high initial
production rates, followed by a steep decline in production. As a result, we
must 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. 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.

OUR FOCUS ON EXPLORATORY 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.

WE DO NOT CONTROL ALL OF OUR OPERATIONS, ESPECIALLY OUR DEEP WATER OPERATIONS.

We do not operate all of our properties and have limited influence over the
operations of some of these properties, particularly our deep water projects.
Our lack of control could result in the following:

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

- 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

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

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

COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
OPERATIONS.

Exploration in the Gulf of Mexico has recently received renewed interest,
especially among major and large independent oil companies. The acquisition of
exploration prospects, producing properties and

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<PAGE> 11

production facilities in the Gulf of Mexico is highly competitive. Factors which
affect our ability to successfully compete are:

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

- our access to seismic, geological and other information, and our ability
to retain the personnel necessary to properly evaluate such information;

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

- the standards we establish for the minimum projected return on an
investment of our capital.

Our competitors include major integrated oil companies and large
independent energy companies, many of which have greater financial and other
resources.

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 -- Capital Expenditures" 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.

INFORMATION IN THIS PROSPECTUS REGARDING OUR PROSPECTS REFLECTS OUR CURRENT
INTENT AND IS SUBJECT TO CHANGE.

We describe our current prospects and our plans to explore these prospects
in this prospectus. A prospect is a property on which we have identified what
our geoscientists believe, based on available seismic and geological
information, to be indications of hydrocarbons. Our prospects are in various
stages of evaluation, ranging from a prospect which is ready to drill to a
prospect which will require substantial additional seismic data processing and
interpretation. Whether we ultimately drill a prospect may depend on the
following factors:

- receipt of additional seismic data or the reprocessing of existing data;

- material changes in oil or gas prices or the costs and availability of
drilling rigs;

- success or failure of wells drilled in similar formations or which would
use the same production facilities;

- availability and cost of capital;

- changes in the estimates of the costs to drill or complete wells;

- our ability to attract other industry partners to acquire a portion of
the working interest to reduce exposure to costs and drilling risks; and

- decisions of our joint working interest owners.

We will continue to gather data about our prospects, and it is possible
that additional information may cause us to alter our drilling schedule or
determine that a prospect should not be pursued at all. You should understand
that our plans regarding our prospects are subject to change.

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YOU SHOULD NOT PLACE UNDUE RELIANCE ON RESERVE INFORMATION BECAUSE RESERVE
INFORMATION REPRESENTS ESTIMATES.

Estimating quantities of proved reserves is inherently imprecise and
involves uncertainties and factors beyond our control. The reserve data in this
prospectus represent only estimates. Such estimates are based upon assumptions
about future production levels, future oil and gas prices and future operating
costs. As a result, the quantity of proved reserves may be subject to downward
or upward adjustment. In addition, estimates of the economically recoverable oil
and gas reserves, classifications of such reserves, and estimates of future net
cash flows, prepared by different engineers or by the same engineers at
different times, may vary substantially. Information about reserves constitutes
forward-looking information. See "Forward-Looking Statements" for information
regarding forward-looking information.

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:

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

- we may experience equipment failure which curtails or stops production;
and

- we could experience blowouts or other damages to the productive
formations which 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 hurricanes and other adverse weather conditions. 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.

THE RECENT DEPRESSED FINANCIAL CONDITIONS IN THE OIL AND GAS INDUSTRY MAY CHANGE
EXPLORATION AND DEVELOPMENT PLANS OR CAUSE DIFFICULTIES IN FINANCING ACTIVITIES.

The recent low prices for oil and gas have limited the access of many
independent oil and gas companies to the capital necessary to finance
activities. Most oil companies have substantially reduced their capital budgets
for 1999 and 2000. As a result, the decision not to drill or complete a well may
be made based on a lack of available capital rather than the quality of the
project. For projects operated by others, we may be unable to control decisions
regarding drilling and completion operations even if those decisions are made
based on capital constraints.

In addition, some of the other working interest owners of our wells may be
unwilling or unable to pay their share of the costs of projects as they become
due. At worst, a working interest owner may declare bankruptcy and refuse or be
unable to pay its share of the cost of a project. In such cases, we could be
required to pay other working interest owner's share of the costs.

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. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Financial Instruments" for a
discussion of our hedging practices. 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

12
<PAGE> 13

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.

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
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may:

- require that we acquire permits before commencing drilling;

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

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

- require remedial measures to mitigate pollution from former operations,
such as plugging abandoned wells.

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. Moreover, 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.

The ability to market oil and gas from our wells depends upon numerous
factors beyond our control. These factors include:

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

- the proximity of the gas production to gas pipelines;

- the availability of pipeline capacity;

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

- the availability of alternative fuel sources;

- the effects of inclement weather;

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

- 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.

13
<PAGE> 14

WE FACE A THREAT OF BUSINESS DISRUPTION FROM THE YEAR 2000 ISSUE.

The year 2000 issue refers to the inability of computer and other
information technology systems to properly process date and time information,
stemming from the outdated programming practice of using two digits rather than
four to represent the year in a date. The consequence of the year 2000 issue is
that computer and embedded processing systems are at risk of malfunctioning,
particularly during the transition from 1999 to 2000. The effects of the year
2000 issue are exacerbated by the interdependence of computer and
telecommunications systems throughout the world. This interdependence also
exists among Callon and our vendors, customers and business partners, as well as
with regulators in the United States.

Our operations are highly dependant on automation. The risks to us
associated with the year 2000 issue fall into three general areas:

- failure of our financial and administrative systems which could result in
our receiving incorrect information upon which we base decisions;

- failure of the embedded systems which control our highly automated
production facilities; and

- failure of our suppliers and purchasers to correct their year 2000
problems.

For a description of the steps we have taken to address the year 2000
issue, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Year 2000 Compliance."

FORWARD-LOOKING STATEMENTS

In this prospectus, 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 prospectus and the documents that are incorporated by
reference into this prospectus. 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:

- the volatility of oil and natural gas prices;

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

- the impact of competition;

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

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

- changes in customer demand;

- the uncertainty of our ability to attract capital;

- changes in the extensive government regulations regarding the oil and
natural gas business; and

- compliance with environmental regulations.

The information contained in this prospectus, 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
those factors.

Our forward-looking statements are expressly qualified in their entirety by
this cautionary statement.

14
<PAGE> 15

USE OF PROCEEDS

We will receive approximately $38.4 million of net proceeds from this
offering after deducting the underwriters' discount and estimated offering
expenses. We intend to use all of the net proceeds, together with our cash flows
and borrowings under our bank credit facility, to fund our remaining 1999
capital expenditure budget, estimated to be $36.2 million, and a portion of our
2000 capital expenditure budget. For a more detailed description of our capital
expenditure budget, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources." Pending
the use of funds to pay capital expenditures, we will use the net proceeds from
the sale of the notes to repay borrowings under our bank credit facility. Our
bank credit facility must be repaid in full on October 31, 2000. As of June 1,
1999, borrowings under our bank credit facility had a weighted average interest
rate of 6.57%.

CAPITALIZATION

The following table sets forth our capitalization, as of March 31, 1999,
and as adjusted to give effect to the sale of the notes and the application of
the estimated net proceeds.

For a description of the application of the net proceeds, see "Use of
Proceeds." You should read this information in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the consolidated financial statements and notes thereto included and
incorporated by reference in this document. As of July 14, 1999, the outstanding
balance under our bank credit facility was $39.1 million.

<TABLE>
<CAPTION>
MARCH 31, 1999
---------------------
AS
HISTORICAL ADJUSTED
---------- --------
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents................................... $ 4,150 $ 16,500
======== ========
Long-term debt:
Credit facility........................................... $ 26,100 $ 100
10% senior subordinated notes............................. 24,150 24,150
10.125% senior subordinated notes......................... 36,000 36,000
The notes offered hereby.................................. -- 40,000
Stockholders' equity:
Preferred stock, $0.01 par value, 2,500,000 shares
authorized; 1,045,461 shares of Convertible
Exchangeable Preferred Stock, Series A issued and
outstanding with a liquidation preference of
$26,136,525............................................ 10 10
Common stock, $0.01 par value, 20,000,000 shares
authorized; 8,545,517 shares outstanding............... 85 85
Treasury stock (98,577 shares at cost).................... (1,177) (1,177)
Capital in excess of par value............................ 108,296 108,296
Retained earnings (deficit)............................... (24,484) (24,484)
-------- --------
Total stockholders' equity........................ 82,730 82,730
-------- --------
Total capitalization.............................. $168,980 $182,980
======== ========
</TABLE>

15
<PAGE> 16

SELECTED FINANCIAL DATA

The following table shows selected financial data for the five years ended
December 31, 1998 and for the three months ended March 31, 1999 and 1998. The
financial data for each of the three years in the period ended December 31, 1998
has been derived from our audited consolidated financial statements for these
periods which are included and incorporated by reference in this prospectus. The
financial data for the years ended December 31, 1995 and 1994 has been derived
from our audited financial statements. The financial data for each of the
three-month periods ended March 31, 1999 and 1998 has been derived from our
unaudited consolidated financial statements for these periods which are also
included in this prospectus. You should read this data in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the consolidated financial statements and notes thereto included
and incorporated by reference in this document. The selected financial data is
not necessarily indicative of our future results.

The following information will help you to better understand the selected
and summary financial data.

- Callon was formed on September 16, 1994. Historical information prior to
September 16, 1994 includes financial and operating information of our
predecessors.

- EBITDA is earnings before interest expense, income tax expense,
depreciation, depletion, amortization and other non-cash charges. EBITDA
is presented because it is a widely accepted financial indication of a
company's ability to service and incur debt. EBITDA should not be
considered as an alternative to earnings (loss) as an indicator of our
operating performance or to cash flow as a measure of liquidity.

- EBITDA, used in the debt to EBITDA ratio and the EBITDA to interest
expense ratio, is calculated using EBITDA for the immediately preceding
four quarters. Interest expense, used in the EBITDA to interest expense
ratio, is calculated using interest expense for the immediately preceding
four quarters.

- For purposes of computing the ratio of earnings to fixed charges,
"earnings" are composed of the following:

- consolidated earnings or loss from continuing operations before tax,
excluding undistributed equity earnings of affiliated companies; plus

- fixed charges, excluding capitalized interest.

Fixed charges are comprised of the following:

- interest expense on indebtedness and capitalized interest;

- amortization of debt issuance costs, discounts and premiums; and

- that portion of capital lease expense which is deemed to be
representative of an interest factor.

Earnings did not cover fixed charges by $262,000 in the first quarter of
1999, $45.9 million in 1998 and $313,000 in 1994.

- 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 the standardized measure, 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 ($28.7 million
after-tax) during the fourth quarter of 1998. The process used to
calculate the standardized measure is described under "Glossary of Oil
and Gas Terms."

16
<PAGE> 17

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEARS ENDED DECEMBER 31,
------------------- --------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- ------- -------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales.............. $ 7,969 $ 11,045 $ 35,624 $ 42,130 $ 25,764 $23,210 $13,948
Interest and other............. 405 447 2,094 1,508 946 627 171
-------- -------- -------- -------- -------- ------- -------
Total revenues............ 8,374 11,492 37,718 43,638 26,710 23,837 14,119
-------- -------- -------- -------- -------- ------- -------
Costs and expenses:
Lease operating expenses....... 1,608 1,941 7,817 8,123 7,562 6,732 4,042
Depreciation, depletion and
amortization................. 3,963 5,570 19,284 16,488 9,832 10,376 6,049
General and administrative..... 1,061 1,502 5,285 4,433 3,495 3,880 3,717
Interest....................... 1,027 651 1,925 1,957 313 1,794 624
Accelerated vesting and
retirement benefits.......... -- -- 5,761 -- -- -- --
Impairment of oil and gas
properties................... -- -- 43,500 -- -- -- --
-------- -------- -------- -------- -------- ------- -------
Total costs and
expenses................ 7,659 9,664 83,572 31,001 21,202 22,782 14,432
-------- -------- -------- -------- -------- ------- -------
Income (loss) from operations.... 715 1,828 (45,854) 12,637 5,508 1,055 (313)
Income tax expense (benefit)... 243 621 (15,100) 4,200 50 -- (200)
-------- -------- -------- -------- -------- ------- -------
Net income (loss)................ 472 1,207 (30,754) 8,437 5,458 1,055 (113)
Preferred stock dividends........ 831 699 2,779 2,795 2,795 256 --
-------- -------- -------- -------- -------- ------- -------
Net income (loss) available to
common shares.................. $ (359) $ 508 $(33,533) $ 5,642 $ 2,663 $ 799 $ (113)
======== ======== ======== ======== ======== ======= =======
Net income (loss) per common
share:
Basic.......................... $ (.04) $ .06 $ (4.17) $ .91 $ .46 $ .14 $ (.03)
Diluted........................ $ (.04) $ .06 $ (4.17) $ .88 $ .45 $ .14 $ (.03)
Shares used in computing net
income (loss) per common share:
Basic.......................... 8,477 8,015 8,034 6,194 5,835 5,755 4,346
Diluted........................ 8,477 8,221 8,034 6,422 5,952 5,755 4,346
STATEMENT OF CASH FLOWS DATA:
Cash provided by operating
activities..................... $ 2,965 $ 9,147 $ 29,721 $ 27,337 $ 14,323 $ 9,452 $ 5,347
Cash used in investing
activities..................... 13,730 12,397 54,196 85,159 36,063 24,237 6,423
Cash provided by (used in)
financing activities........... 8,615 (673) 15,178 65,750 25,144 11,765 3,916
BALANCE SHEET DATA (END OF PERIOD):
Working capital.................. $ 576 $ 7,880 $ 1,142 $ 12,719 $ 4,878 $ 4,712 $ 1,896
Oil and gas properties, net...... 151,963 111,213 141,905 150,494 82,489 57,765 43,920
Total assets..................... 188,457 191,615 181,652 190,421 118,520 83,867 73,786
Total debt....................... 92,231 60,250 81,250 60,250 24,250 100 15,363
Stockholders' equity............. 82,730 114,788 84,484 113,701 77,864 75,129 43,431
OTHER FINANCIAL DATA:
Capital expenditures, net........ $ 13,730 $ 12,397 $ 54,196 $ 85,159 $ 36,063 $24,237 $10,412
EBITDA........................... $ 6,116 $ 8,974 $ 27,564 $ 33,209 $ 16,138 $13,582 $ 6,727
Ratio of EBITDA to interest
expense........................ 10.7x 12.9x 14.3x 17.0x 51.6x 7.6x 10.8x
Ratio of earnings to fixed
charges........................ -- 1.7x -- 3.3x 8.8x 1.6x --
Ratio of total debt to EBITDA.... 3.7x 1.9x 2.9x 1.8x 1.5x .0x 2.9x
</TABLE>

17
<PAGE> 18

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

Our results of operations are primarily influenced by the prices we receive
for oil and gas production and the costs we incur to produce oil and gas. The
following table shows information about our prices and costs. Prices shown below
include the effects of our hedging activities.

<TABLE>
<CAPTION>
THREE MONTHS
ENDED MARCH 31, YEARS ENDED DECEMBER 31,
--------------- --------------------------
1999 1998 1998 1997 1996
------ ------ ------- ------- ------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls)................................... 90 112 310 462 585
Gas (MMcf).................................... 3,369 4,036 14,036 13,114 6,269
Total production (MMcfe)...................... 3,909 4,706 15,894 15,887 9,781

AVERAGE SALES PRICE:
Oil (per Bbl)................................. $11.49 $13.85 $ 12.41 $ 18.63 $18.27
Gas (per Mcf)................................. 2.06 2.35 2.26 2.56 2.40
Total production (per Mcfe)................... 2.04 2.35 2.24 2.65 2.63

AVERAGE COSTS (PER MCFE):
Lease operating expenses (excluding severance
taxes)..................................... $ .35 $ .34 $ .44 $ .42 $ .57
Severance taxes............................... .06 .07 .06 .09 .20
Depreciation, depletion and amortization...... 1.01 1.18 1.19 1.04 1.01
General and administrative (net of management
fees)...................................... .27 .32 .33 .28 .36
</TABLE>

Since 1996, we have completed several acquisitions that have significantly
affected our results of operations. Through a series of four transactions, we
acquired 52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area
for a total acquisition cost of $48.7 million. In June 1999, in exchange for a
production payment, we acquired Murphy's interest in several wells and
undeveloped acreage in this area which, prior to exploration and development
activities, has added an additional 15.6 Bcf of estimated net proved reserves.

Our results in 1998 were also affected by the sale of our Black Bay Complex
properties which are located in Louisiana state waters. We sold these properties
in April 1998 for $9.4 million, the proceeds of which were used to repay amounts
outstanding under our revolving credit facility.

Inflation has not had a material impact on our results of operations and is
not expected to have a material impact on our results of operations in the
future.

Comparison of Results of Operations for the Three Months Ended March 31, 1999
and 1998

Our oil and gas revenues for the first three months of 1999 were $8.0
million, a 28% reduction from $11.0 million for the same period in 1998. On a
Mcfe basis, our first quarter 1999 production decreased 17% from 4.7 Bcfe in
1998 to 3.9 Bcfe in 1999. Our revenues were further reduced by the 13% reduction
in average sales price per Mcfe.

Oil production during the first quarter of 1999 totaled 90.0 MBbls and
generated $1.0 million in revenues compared to 112.0 MBbls and $1.5 million in
revenues for the same period in 1998. The reduction in revenues during the 1999
period resulted from a 17% reduction in the average sales price received and a
20% lower production rate. Average oil prices, including the effects of hedging,
received in the first quarter of 1999 were $11.49 compared to $13.85 in the
first quarter of 1998. The first quarter average daily oil production decreased
from 1.2 MBbls per day in 1998 to 1.0 MBbls per day in 1999.

18
<PAGE> 19

Approximately 442.0 Bbls per day of the reduced production was attributable to
the sale of the Black Bay Complex which was partially offset by the addition of
approximately 22.0 MBbls of oil from our discoveries in the OCS area. Other
properties also experienced a natural decline in production.

Gas production volumes during the first quarter of 1998 totaled 4.0 Bcf and
generated $9.5 million in revenues compared with 3.4 Bcf and $6.9 million in
revenues during the same period in 1999. The first quarter average daily gas
production decreased from 44.8 MMcf per day in 1998 to 37.4 MMcf per day in
1999. The average sales price (including the effects of hedging) for the first
quarter of 1999 was $2.06 per Mcf compared with $2.35 per Mcf for the same
period of 1998. The reduced production volumes were caused by the expected
decline curves of our shallow Miocene and OCS properties.

Lease operating expenses, including severance taxes, for the three-month
period ended March 31, 1999 were $1.6 million, a decrease from the $1.9 million
for the three-month period ended March 31, 1998. On a per Mcfe basis, these
combined expenses remained at $0.41 as a result of lower production volumes and
proportionate decreases in field operating costs.

Depreciation, depletion and amortization for the three month periods ended
March 31, 1999 and 1998 were $4.0 million and $5.6 million, respectively. This
decrease reflects decreased production volumes and a lower overall rate per
Mcfe, primarily as a result of a fourth quarter 1998 full-cost ceiling
impairment. For the three-month period ended March 31, 1999, the per Mcfe amount
was $1.01 compared to $1.18 for the same period in 1998.

General and administrative expenses for the three-month period ended March
31, 1999 were $1.0 million compared to $1.5 million for the three-month period
ended March 31, 1998. This reduction was attributable to first quarter 1999
expenses not including any charges for bonuses under the incentive compensation
plan nor amortization of expenses associated with the vesting of performance
shares as none were awarded or vested during such period. On a per Mcfe basis,
general and administrative expenses decreased from $0.32 in the first quarter of
1998 to $0.27 in the first quarter of 1999.

Interest expense for the first quarter of 1999 increased as a result of
increased long-term debt when compared to the first quarter debt level in 1998.
For the period ended March 31, 1999, interest expense was $1.0 million compared
to $0.7 million for the first quarter of 1998, net of interest capitalized as
property costs.

Income taxes were recorded at the statutory rate of 34% of net income for
both periods.

Preferred stock dividends were $0.8 million for the first quarter of 1999
as compared to $0.7 million for the first quarter of 1998. During the first
quarter of 1999, several preferred stockholders, through private transactions,
agreed to convert 210,350 shares of series A preferred stock into 502,632 shares
of our common stock. Of these shares of common stock, 24,507 shares were issued
in excess of the conversion rate as a result of private negotiations between us
and the holders. These additional shares were treated as a non-cash dividend on
the preferred stock for accounting purposes and were valued at the market value
of the shares on the date of conversion. Cash dividends on the series A
preferred stock will be lower in future quarters since the number of shares
outstanding has been reduced.

Comparison of Results of Operations for the Years Ended December 31, 1998 and
1997

Our oil and gas revenues for 1998 were $35.6 million, a 15% reduction from
$42.1 million in 1997. On a Mcfe basis, our 1998 production was the same as that
reported for 1997. The reduction in our revenues was attributable to the 15%
reduction in average sales price (including the effects of hedging) per Mcfe.

Oil revenues declined from $8.6 million to $3.8 million. This decline was
caused in part by reduced oil production, which declined from 462.0 MBbls in
1997 to 310.0 MBbls in 1998 and a decline in average sales prices (including the
effects of hedging) from $18.63 in 1997 to $12.41 in 1998. Approximately 5% of
the reduced production was attributable to the sale of the Black Bay Complex in
1998, and the remainder was attributable to normal production declines.

19
<PAGE> 20

Our gas revenues for 1998 were $31.8 million, a reduction of 5% from 1997
revenues of $33.5 million. Gas production in 1998 was 14.0 Bcf, an increase of
7% over 1997 production of 13.1 Bcf. The increase in production was attributable
to the beginning of production from exploration successes in 1998. The increases
in production were more than offset by a reduction in average prices (including
the effects of hedging) from $2.56 per Mcf in 1997 to $2.26 in 1998.

Our lease operating expenses, including severance taxes, decreased from
$8.1 million in 1997 to $7.8 million in 1998. This decrease was attributable to
reduced severance taxes which declined from $1.4 million in 1997 to $0.9 million
in 1998 because more of our production was from federal waters where we do not
incur severance taxes. The other components of operating expenses increased from
$6.7 million in 1997 to $6.9 million in 1998 as a result of a full year of costs
associated with acquisitions in the fourth quarter of 1997 that was partially
offset by a reduction in costs due to the sale of the Black Bay Complex.

Depreciation, depletion and amortization increased as a higher rate was
applied to a relatively constant production volume. Total charges increased from
$16.5 million, or $1.04 per Mcfe, in 1997 to $19.3 million, or $1.19 per Mcfe in
1998. The increase in the noncash charge per Mcfe reflects the increase in
investment in evaluated oil and gas properties during 1998.

Our general and administrative expenses for 1998 were $5.3 million, or $.33
per Mcfe, compared to $4.4 million, or $.28 per Mcfe, in 1997. This 19% increase
was primarily the result of the loss of Black Bay management fees, which
previously reduced general and administrative expenses, and slightly higher
corporate expenses.

Interest expense was $1.9 million for 1998 and $2.0 million for 1997.

In December 1998, we recorded a charge of $5.8 million attributable to the
accelerated vesting of the remaining unvested performance shares previously
granted under our stock option plans and of retirement benefits.

Under the full-cost method of accounting, the net capitalized costs of
proved oil and gas properties are subject to a "ceiling test," which limits such
costs to the discounted present value, net of related tax effects, of proved
reserves. If capitalized costs exceed this limit, the excess is charged to
expense. During the fourth quarter of 1998, we recorded a noncash impairment
provision related to oil and gas properties in the amount of $43.5 million
($28.7 million after-tax) primarily due to the significant decline in oil and
gas prices.

Our 1998 results included a deferred income tax benefit of $15.1 million
primarily due to the $14.8 million deferred income tax benefit related to
impairment of oil and gas properties recorded in 1998. We expect to realize this
benefit for tax purposes in future years by utilizing our net operating loss and
statutory depletion carryforwards. We have evaluated the potential realization
of the deferred income tax benefit recorded above in light of our reserve
quantity estimates, our long-term outlook for oil and gas prices and our
expected level of other future expenses. We believe it is more likely than not,
based upon this evaluation, that we will realize the recorded deferred income
tax asset. However, we cannot assure you that such asset will ultimately be
realized.

Comparison of Results of Operations for the Years Ended December 31, 1997 and
1996

Our total oil and gas revenues increased $16.4 million, or 63%, during 1997
to $42.1 million compared to $25.8 million in 1996. This increase in oil and gas
revenues was the result of increased gas production volumes and increased
average sales prices (including the effects of hedging) for both oil and gas.

Our oil revenues for 1997 were $8.6 million based on production volume of
462.0 MBbls sold at an average sales price of $18.63 per Bbl. For 1996, our
revenues were $10.7 million based on 585.0 MBbls of oil sold at an average sales
price (including the effects of hedging) of $18.27. The $2.1 million decline in
oil revenues was largely attributed to normal production declines from several
of our oil producing properties, as well as the divestiture of certain non-core
properties.

20
<PAGE> 21

Our gas revenues for 1997 were $33.5 million from production volumes of
13.1 Bcf of gas sold at an average sales price of $2.56 per Mcf. For 1996, our
revenues were $15.1 million from the production of 6.3 Bcf of gas sold at an
average sales price (including the effects of hedging) of $2.40. The 109%
increase in production volume was largely attributed to our 1996 discoveries in
the OCS and shallow Miocene areas.

Lease operating expenses, including severance taxes, increased from $7.6
million in 1996 to $8.1 million in 1997. Separately, severance taxes declined
from $1.9 million in 1996 to $1.4 million in 1997 as a result of lower
production on properties subject to severance taxes. Other operating expenses
increased from $5.6 million in 1996 to $6.7 million in 1997 as a result of the
new offshore producing properties. On a per Mcfe basis, these combined expenses
decreased from $0.77 in 1996 to $0.51 in 1997.

Depreciation, depletion and amortization for 1997 totaled $16.5 million, or
$1.04 per Mcfe. For the same period in 1996, these expenses totaled $9.8
million, or $1.01 per Mcfe.

Our general and administrative expenses for 1997 were $4.4 million, a 27%
increase from the $3.5 million in 1996 as a result of expanded levels of
operations and production. On a per Mcfe basis, these expenses decreased from
$.36 in 1996 to $.28 in 1997.

Interest expense for 1997 was $2.0 million. The substantial increase from
the $.3 million in 1996 was reflective of the issuance of senior subordinated
notes in November 1996 and July 1997.

Income tax expense for 1997 was $4.2 million. This amount represented the
approximate statutory income tax rate, as adjusted for expected future
utilization of our net operating losses and depletion carryovers. For 1996, the
statutory income tax was $1.9 million, which was primarily offset by a reduction
in the deferred tax asset valuation allowance.

LIQUIDITY AND CAPITAL RESOURCES

Capital Sources

Our primary sources of capital are cash flows from operations, borrowings
under our bank credit facility, and sales of debt and equity securities. Cash
flow from operations before working capital changes for the first quarter of
1999 and 1998 totaled $5.1 million and $8.3 million, respectively. During the
first three months of 1999, borrowings under our credit facility increased by
$8.0 million. Borrowings under the credit facility increased $18.0 million
during 1998. Also during 1998, we sold properties in the Black Bay Complex for
net cash proceeds of $9.4 million, which was used to reduce the amount
outstanding under our credit facility.

Bank credit facility. Borrowings under the bank credit facility are secured
by mortgages covering substantially all of our producing oil and gas properties.
The credit facility provides for a borrowing base which is adjusted periodically
on the basis of the discounted present value attributable to our proved
producing oil and gas reserves, as determined by the bank. The credit facility
currently provides for a $50.0 million borrowing base. The borrowing base is
currently being reevaluated with the bank. We expect that upon the closing of
the sale of the notes, the borrowing base will be decreased. We may borrow, pay,
reborrow and repay under the credit facility until October 31, 2000, on which
date we must repay in full all amounts then outstanding. At July 14, 1999, the
amount available to be borrowed under our credit facility was approximately
$10.9 million. See "Description of Bank Credit Facility and Other
Indebtedness -- Bank Credit Facility" for more information about the credit
facility.

Material sales of debt and equity securities. In November 1996, we issued
$24.2 million of 10% senior subordinated notes and in July 1997, we issued $36
million of 10.125% senior subordinated notes for total net proceeds of $58.4
million. The proceeds of the note offerings were used to repay outstanding
amounts under the bank credit facility. See "Description of Bank Credit Facility
and Other Indebtedness -- Outstanding Notes" for additional information about
our outstanding notes.

On November 25, 1997, we sold 1.8 million shares of our common stock to the
public for total net proceeds of $29.3 million. We used a portion of the
proceeds to repay indebtedness incurred to finance the

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<PAGE> 22

purchase of properties in the shallow Miocene area and the balance to fund a
portion of our 1998 capital expenditure budget.

Capital Expenditures

Capital expenditures for the first three months of 1999 and for the year
1998 were $14.0 million and $64.1 million, respectively. The 1999 amounts were
used primarily to drill and complete four wells, and to complete two previously
drilled wells. The 1998 amount included $9.5 million for the acquisition of
producing properties and equipment, $47.0 million for property development and
drilling activities and $7.3 million for the acquisition of oil and gas
properties for exploration.

Our capital expenditure budget for the last three quarters of 1999 is $36.2
million. The major portion of the capital expenditure budget will be used to
drill and complete seven exploration wells. The total estimated 1999 dry hole
costs to drill these wells are $12.4 million, and the costs to complete these
wells are $9.1 million. The timing and cost to drill these wells will depend
upon numerous factors, many of which are beyond our control.

In addition, we have a non-cash expenditure related to the acquisition of
Murphy's interest in Mobile Block 864. We acquired Murphy's interest for
approximately $15.0 million, financed by a volumetric production payment.

We make offers for producing properties in the ordinary course of our
business. If we were to purchase a producing property, our capital budget could
change materially.

Financial Instruments

We periodically use derivative financial instruments to hedge oil and gas
price risks. In a typical hedge transaction, we will have the right to receive
from counterparties 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 counterparties the 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. If there
are significant reductions in production at times when the floating price
exceeds the fixed price, we could be required 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.

We also enter into price "collars" to reduce the risk of changes in oil and
gas prices. Under a collar, no payments are due by either party so long as the
market price is above a floor set in the collar and below a ceiling. If the
price falls below the floor, the counter-party to the collar pays the difference
to us and if the price is above the ceiling, we pay the counter-party the
difference. We enter into hedge transactions to reduce the effect of volatile
oil and gas prices, and do not enter into hedge transactions for speculative
purposes.

As of March 31, 1999, we had hedged approximately 483 MMcf per month
through September 1999, representing 39.0% of our estimated gas production
during this period, pursuant to price collars, with an average NYMEX floor price
of $1.85 per MMBtu (NYMEX) and an average ceiling price of $2.12 per MMBtu. Also
at March 31, 1999, we had open forward natural gas swap contracts of 200 MMcf
per month from April 1999 through September 1999, representing 16.0% of our
estimated gas production during this period, at a fixed contract average price
of $2.35. In addition, we had oil price collar contracts for 24.2 MBbls per
month from April 1999 through December 1999, representing 78.0% of our estimated
oil production during this period, at a ceiling price of $16.15 and a floor of
$13.78. We also had crude oil swap contracts of 10 MBbls per month with a fixed
contract price of $14.10 per month from April 1999 through June 1999,
representing 34.0% of our estimated oil production during this period.

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<PAGE> 23

YEAR 2000 COMPLIANCE

Three years ago, we began our efforts to address the threats to our
business posed by the year 2000 issue. For a description of the business
disruption risks we face from the year 2000 issue, see "Risk Factors."
Overseeing the year 2000 project is the Callon Year 2000 Project Committee which
meets on a periodic basis to review project status, provide necessary management
input and resolve project issues on a timely basis. A formal review is presented
to our board of directors periodically.

Our plan is divided into three phases. Phase one involves a physical
inventory of all hardware, software and devices containing date-oriented
firmware. Phase two requires that we prioritize issues, obtain or devise
solutions and make repairs or replace equipment as necessary. The third phase of
the plan calls for the development of contingency plans to address, among other
things, the failure of our business partners to adequately address their year
2000 problems.

We have completed phase one and have substantially completed phase two. We
are continuing to work on phase three and expect completion in the third quarter
of 1999.

Accounting systems. Our core financial accounting software is maintained by
one major vendor of oil and gas industry software. The vendor has indicated that
it believes our system is year 2000 compliant.

Embedded chips. A substantial portion of our exploration and production
facilities are automated. These facilities rely on one or more "embedded chips"
to control and measure flow rates, pressures, emissions and other critical
functions. Failure of embedded chips may cause production to stop, spills of
hydrocarbons or other materials and other problems. This problem is complicated
because many of the embedded chips are linked in systems, where the failure of
one part of the system will adversely affect the entire facility.

We believe we have identified all of the embedded systems affecting our
material facilities, tested them for year 2000 compliance and made appropriate
remediation. We therefore do not expect that our embedded systems will suffer
material interruptions caused by year 2000 related failures of our systems. It
must be noted, however, that our facilities have numerous embedded chips many of
which are not easy to locate. In addition, while we believe the testing of chips
will uncover year 2000 failures, until the year 2000 occurs, there is no way to
be sure that the repairs we made will work, or that all of the embedded chips
which must work together in systems will function properly. Because of the
complexity of the year 2000 problem, we cannot assure you that we will not have
a material business interruption caused by the year 2000 problem.

Vendors and customers. We could be adversely affected if our suppliers,
customers or other business partners experience year 2000 failures. For example,
if our electrical supplier fails to deliver electricity to our facilities or if
refineries are unable to receive our oil production, we will suffer losses. We
have requested information from all of our material business partners regarding
their year 2000 readiness. It appears that all of our material business partners
are aware of the year 2000 issues and are attempting to uncover and remedy
potential failures. Where we were not satisfied with the results of our
inquiries, we are attempting to develop contingency plans. However, we do not
believe contingency plans will protect us from loss if there are material year
2000 failures of our business partners. Additionally, we are unable to
independently verify that our business partners are, in fact, taking appropriate
steps to remedy problems. Accordingly, no assurances can be made that year 2000
failures will not adversely affect our business.

Estimated compliance costs. Our total costs incurred to date and estimated
remaining costs for consultants, software and hardware applications for the year
2000 project are less than $200,000. We do not separately account for the
internal costs incurred for our year 2000 compliance efforts, which consist
principally of payroll and related benefits for our informations system
personnel.

Risks of non-compliance. The most reasonably likely "worst case" impact of
the year 2000 issue on our operations could be:

- hydrocarbon spills or other accidents which could result in environmental
pollution, personal injuries or loss of life;

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<PAGE> 24

- equipment failures which could curtail, delay or cancel our operations;

- impairment of our ability to deliver our production to, or receive
payment from, third parties gathering and/or purchasing our production
from affected facilities;

- impairment of the ability of third-party suppliers or service companies
to provide needed materials or services to our planned or ongoing
operations, thereby necessitating deferral or shut-in of our operations;
and

- our inability to execute financial transactions with our banks or other
third parties whose systems fail or malfunction.

We have no reason to believe that any of these contingencies will occur or
that our principal vendors, customers and business partners will not be year
2000 compliant.

DISCLOSURES ABOUT MARKET RISKS

Our revenues are derived from the sale of our oil and natural gas. The
prices of oil and gas are extremely volatile, and experience large fluctuations
as a result of relatively small changes in supplies. For a description of the
effects of the volatility of oil and gas prices on our operations, see "Risk
Factors."

From time to time we enter into arrangements to reduce the effect of
changes in oil and gas prices upon our revenues as described above under
"Liquidity and Capital Resources -- Financial Instruments."

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<PAGE> 25

BUSINESS AND PROPERTIES

Callon has been engaged in the exploration, development, acquisition and
production of oil and gas in the Gulf Coast region since 1950. Our properties
and operations are geographically concentrated in the offshore waters of the
Gulf of Mexico where we have substantial experience. As of June 1, 1999, we had
estimated net proved reserves of 183.3 Bcfe which had a discounted present value
of $173.9 million. Reserves comprising 72% of this discounted present value were
classified as proved developed. Average daily net production during the first
quarter of 1999 was 43.4 MMcfe, of which 86% was natural gas. We operate wells
representing 82% of this production. As of June 1, 1999, our reserve life was
12.1 years.

Our activities are concentrated in the Gulf of Mexico, where we conduct
operations in three areas:

- The shallow Miocene area, where we have controlling working interests in
projects with low exploration risk and low drilling and completion costs,
targeting reserve deposits of between 3 and 10 Bcf at depths of less than
4,000 feet. Wells are typically drilled from existing platforms or near
existing pipelines so that they can be brought on line quickly and
inexpensively. We have an average net working interest of 83% in, and
operate all of, our shallow Miocene wells.

- The outer continental shelf area, where we have significant working
interests in projects with higher exploration risk and higher drilling
and completion costs, targeting reserve deposits of between 10 and 100
Bcfe at depths of between 7,000 and 17,000 feet. We have a weighted
average net working interest of 65.4%, and operate wells representing
61.5% of our estimated net proved reserves, in the OCS area.

- The deep water area, where we have small working interests in projects
with high exploration risk and high drilling and completion costs,
targeting large reserve deposits. We do not operate wells in the deep
water area, and we intend to own less than a 15.0% interest in our deep
water wells.

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<PAGE> 26

The following table provides information about our estimated net proved
reserves in these areas as of June 1, 1999.

<TABLE>
<CAPTION>
PERCENT
ESTIMATED NET PROVED RESERVES DISCOUNTED TOTAL
------------------------------ PRESENT DISCOUNTED
PRIMARY GAS OIL TOTAL VALUE PRESENT
AREA NAME OPERATOR (MMCF) (MBBLS) (MMCFE) ($000) VALUE
- --------- ----------- -------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
SHALLOW MIOCENE AREA:
Mobile Block 864 Area............. Callon 52,719 -- 52,719 $ 66,607 38.3%
Chandeleur Block 40............... Callon 3,739 -- 3,739 3,456 2.0%
Other............................. Callon 1,448 -- 1,448 1,072 0.6%
------- ------ ------- -------- -----
Total................... 57,906 -- 57,906 71,135 40.9%
------- ------ ------- -------- -----
OCS AREA:
BRETON SOUND:
Main Pass 26 SL 15827............. Callon 5,180 363 7,355 9,374 5.4%
Main Pass 31 SL 12002............. Callon 1,619 32 1,813 3,313 1.9%
Main Pass 36 SL 14964
"Garfield"..................... Callon 4,183 161 5,149 7,550 4.3%
Other Breton Sound................ Callon 714 217 2,018 1,909 1.1%
------- ------ ------- -------- -----
Total Breton Sound........ 11,696 773 16,335 22,146 12.7%
------- ------ ------- -------- -----
OTHER OCS:
High Island Block A-494
"Snapper"...................... PetroQuest 4,953 -- 4,953 7,723 4.4%
Eugene Island Block 335........... Murphy 3,003 174 4,050 6,698 3.9%
Vermilion Block 130............... Murphy 1,187 4 1,208 1,589 0.9%
------- ------ ------- -------- -----
Total Other OCS........... 9,143 178 10,211 16,010 9.2%
------- ------ ------- -------- -----
Total................... 20,839 951 26,546 38,156 21.9%
------- ------ ------- -------- -----
DEEP WATER AREA:
Ewing Bank Block 994 "Boomslang".. Murphy 8,282 4,601 35,889 14,341 8.2%
Garden Banks Block 341
"Habanero"..................... Shell 12,547 6,393 50,902 34,646 19.9%
------- ------ ------- -------- -----
Total................... 20,829 10,994 86,791 48,987 28.2%
------- ------ ------- -------- -----
OTHER AREAS......................... Various 5,399 1,106 12,034 15,639 9.0%
------- ------ ------- -------- -----
Total................... 104,973 13,051 183,277 $173,917 100.0%
======= ====== ======= ======== =====
</TABLE>

SHALLOW MIOCENE PROPERTIES

In the shallow Miocene area, we explore for gas deposits using 3-D and
conventional 2-D seismic technology, as well as a proprietary high-resolution
2-D seismic technology which better defines reservoir thickness and continuity.
We have an average working interest in productive wells in the shallow Miocene
area of 83.0%, all of which we operate. Since 1996, we have drilled three gross
(2.7 net) exploration wells, of which two gross (2.0 net) were productive, and
two gross (1.5 net) development wells, both of which were productive. Our
drilling activities in the shallow Miocene area have added 11.2 Bcf of estimated
net proved reserves at a cost to us of $9.5 million to drill and complete. We
have acquired an extensive infrastructure of production platforms, gathering
systems and pipelines located in our shallow Miocene area. These facilities
reduce the development costs of our successful wells and reduce the time
necessary to begin production from successful wells. In 1997, we also acquired
52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area for a
total acquisition cost of $48.7 million. We have acquired additional interests
in this area. We currently have an inventory of four exploration prospects in
this area, two of which we expect to drill before year-end 1999.

We own 110,000 gross (94,000 net) acres in 18 federal blocks and various
state leases in the shallow Miocene area, and have an average 83.0% net working
interest in 21 producing wells which had average net daily production of 24.8
MMcf during the first quarter of 1999. Since 1996, we have acquired 3,000

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<PAGE> 27

miles of seismic data in this area. The following is a description of the
current areas in which we have activities in the shallow Miocene area.

Mobile Block 864 Area

The Mobile Block 864 area is located offshore Alabama in federal waters.
During 1997, we consummated four acquisitions of producing properties and
developed and undeveloped acreage in this area for a total of $48.7 million. In
June 1999, we acquired additional interests in the area in exchange for a
production payment requiring us to deliver 7.6 Bcf of gas over the next three
and one quarter years. In total, we own an average 81.1% working interest in ten
blocks. Production from a reservoir that underlies four of the blocks has been
unitized. We now own a 66.4% working interest in the four well unit and the unit
production facilities. We also own a 100% working interest in three additional
producing wells in this area. We are the operator of the Mobile Block 864 unit.
Estimated net proved reserves at June 1, 1999, including the Murphy transaction
which closed on June 11, were 57.9 Bcf with a discounted present value of $67.0
million. Net average daily production during the first quarter of 1999 was 14.0
MMcf.

Production from three wells in the area is currently constrained by the
compression of the unit production facilities. We plan to upgrade the facilities
to increase production capacity during 1999.

Chandeleur Block 40

Chandeleur Block 40 is located offshore Louisiana in federal waters. In
December 1995, we acquired an additional working interest in Chandeleur Block
40, increasing our interest to 52.3%. When we assumed operations of the field,
two wells were producing 5.5 MMcf per day of gas from the 3,800-foot sand. In
February 1996, we shut-in one well and successfully reworked the other and
increased average field production to 10.5 MMcf per day of natural gas. During
the fourth quarter of 1996, we drilled a development well in the field. The well
resulted in a field extension which added 5.0 Bcf in estimated net proved
reserves as of December 31, 1996. We are the operator of Chandeleur Block 40.
Estimated net proved reserves at June 1, 1999 were 3.7 Bcf with a discounted
present value of $3.5 million. Net average daily production during the first
quarter of 1999 was 3.4 MMcf.

OUTER CONTINENTAL SHELF PROPERTIES

We explore for oil and gas deposits in the OCS area of the Gulf of Mexico
using the latest in 3-D seismic technology. The wells drilled in this area are
more expensive than the shallow Miocene wells and target larger oil and gas
deposits. Our weighted average working interest in productive wells in the OCS
area is 65.4%. Since 1996, we have added 28.6 Bcfe of estimated net proved
reserves at a cost to us of $28.3 million to drill and complete. Since 1996, we
have drilled 13 gross (5.5 net) exploration wells in this area, of which five
gross (2.8 net) were productive. We also drilled three gross (1.4 net)
development wells, all of which were successful, and we currently have one gross
(0.9 net) exploration well in progress. We currently have an inventory of 20
exploration prospects in this area, nine of which we expect to drill before
year-end 2000.

We own 169,000 gross (61,000 net acres) in 32 federal blocks and various
state leases in the OCS area, including the Breton Sound, and have an average
75% working interest in 19 producing wells which during March 1999 had average
net daily production of 16.7 MMcfe. Since 1996, we have acquired 450 square
miles of 3-D seismic data in this area. The following is a description of the
current areas in which we have activities in the OCS.

Breton Sound Area

The Breton Sound area, located in Louisiana state waters, has been a
significant operating area for us since 1997. We have acquired an extensive
infrastructure of pipelines, platforms and other production facilities in this
area. We own an 84.2% weighted average working interest in 13 wells in this
area, all of which we operate, producing from depths of between 6,000 and 13,000
feet. Nine of these wells are burdened by an 80.8% net profits interest held by
an institutional investor. During March 1999, net average
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<PAGE> 28

daily production from this area was 13.8 MMcfe. Our Garfield well is scheduled
to commence production by the end of June 1999.

The following is a description of several of our properties in this area:

Main Pass 26/SL 15827. We negotiated a farm-in agreement in 1998 for a
97.0% working interest after identifying a prospect on the Main Pass 26
Block based upon a seismic survey we completed in 1996. In August 1998, we
drilled a well to a depth of 10,450 feet. The SL 15827 well was producing
during March 1999 at a net average daily rate of 3.7 MMcf and 229.0 Bbls of
oil. Estimated net proved reserves attributable to this well as of June 1,
1999 were 7.4 Bcfe with a discounted present value of $9.4 million. We
operate this well.

Main Pass 31/SL 12002. Based upon a 1996 seismic survey that we
completed, we negotiated two separate farm-in agreements for a 100.0%
working interest covering a prospect on Main Pass Block 31. In August 1997,
the SL 12002 was drilled to a vertical depth of 10,900 feet. We completed
the well and placed it on production in December 1997 after flowlines were
laid to a facility we operate at Main Pass Block 32. The well produced 1.9
Bcf and 72.0 MBbls of condensate before being recompleted in the fourth
quarter of 1998. The well was brought back on-line during the first quarter
of 1999 and produced at net average daily rates of 6.9 MMcf and 227.0 Bbls
per day. Estimated net proved reserves attributable to this well as of June
1, 1999 were 1.8 Bcfe with a discounted present value of $3.3 million. We
operate this well.

Main Pass 36/SL 14964 "Garfield." We acquired a 50.0% working interest
in a prospect on Main Pass Block 36 from Conoco in July 1998. In August
1998, we completed the Garfield well, which has 40 feet of net gas pay in
three zones from 13,300 feet to 16,500 feet and was tested at 14.0 MMcf and
900.0 Bbls of condensate per day. Production is scheduled to begin by the
end of June 1999. Estimated net proved reserves attributable to this well
as of June 1, 1999 were 5.1 Bcfe with a discounted present value of $7.6
million. We operate this well.

Other OCS Areas

In 1997 we expanded our operations in the OCS area beyond Breton Sound
primarily through an exploration joint venture with Murphy Exploration and
Production, Inc. Since 1996, we have generally limited our working interests in
these prospects to 25.0%. Recently, however, we have sought to increase our
interests in these prospects and, in some cases, acquire operations. Estimated
net proved reserves at June 1, 1999 were 10.2 Bcfe with a discounted present
value of $16.0 million. Net average daily production during the first quarter of
1999 was 2.9 MMcfe. The following is a description of several of the significant
properties we own in the OCS area outside of Breton Sound.

High Island Block A-494, "Snapper." In January 1999, we announced a
discovery on our Snapper prospect, which was drilled to a total depth of
8,800 feet. We own a 50.0% working interest in this well, which we
purchased in 1998 from PetroQuest Energy Inc., the operator. The well is
scheduled to begin production by the end of June 1999 through production
facilities designed to handle 15.0 MMcf per day. Estimated net proved
reserves attributable to this well at June 1, 1999 were 5.0 Bcf with a
discounted present value of $7.7 million.

Eugene Island Block 335. In 1997, we drilled three wells on Eugene
Island Block 335, which we acquired in an OCS lease sale. We own a 20.0%
working interest in the wells, which are operated by Murphy. During March
of 1999, the three wells produced at a net average daily rate of 2.5 MMcfe.
Estimated net proved reserves attributable to these wells at June 1, 1999
were 4.1 Bcfe with a discounted present value of $6.7 million.

Vermilion Block 130. In March 1998, we drilled a successful well on
this block, which we acquired in an OCS lease sale, to a total depth of
14,134 feet. We own a 25.0% working interest in this well, which is
operated by Murphy. During the first quarter of 1999, the well produced at
a net average daily rate of 0.4 MMcfe from one of three proved zones.
Estimated net proved reserves attributable to this well at June 1, 1999
were 1.2 Bcfe with a discounted present value of $1.6 million.
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<PAGE> 29

DEEP WATER PROPERTIES

We allocate a portion of our capital expenditure budget to the exploration
of deep water regions in the Gulf of Mexico. These wells are expensive to drill
and complete and target large reserve deposits. These wells are usually located
far from production facilities and may require long lead times to construct
pipelines and other facilities necessary to begin producing reserves we
discover. To reduce the risks associated with the high cost of these wells, we
explore these prospects with experienced joint venture partners, including Shell
Deepwater Development, Inc. and Murphy Exploration and Production, Inc. as
operators. We have drilled two wells in our deep water area, both of which were
successful. In September 1998, we announced a discovery on our "Boomslang"
prospect, and in February 1999, we announced a discovery on our "Habanero"
prospect. These discoveries represent the largest discoveries in our history and
have added estimated net proved reserves of 86.8 Bcfe at a cost to us of $10.2
million to drill. Costs to complete these wells cannot be determined until we
drill several related prospects. We currently have an inventory of 15 deep water
exploration prospects, four of which we expect to drill before year-end 2000.

We own 132,000 gross (24,000 net) acres in 23 blocks in the deep water
areas of the Gulf of Mexico. The following is a description of the two deep
water prospects which have been drilled to date, both of which were successful
and represent the largest discoveries in our history.

Ewing Bank Block 994 "Boomslang." In September 1998, we announced a
discovery on our Boomslang prospect which we acquired in an OCS lease sale.
This well was drilled in 900 feet of water to a total depth of 13,200 feet.
We own a 35.0% working interest in the well, which is operated by Murphy.
Estimated net proved reserves at June 1, 1999 were 35.9 Bcfe, with a
discounted present value of $14.3 million. Prior to designing production
facilities for Boomslang, we plan to drill the Sidewinder prospect. See
"Exploration and Development Activities -- Deep Water Area" for a
description of the Sidewinder prospect.

Garden Banks Block 341 "Habanero." In February 1999, we announced a
discovery on our Habanero prospect which we acquired from Shell in exchange
for other interests we held on the block. This well was drilled in 2,000
feet of water to a total depth of 21,158 feet. We own an 11.3% working
interest in the well, which is operated by Shell. Estimated net proved
reserves at June 1, 1999 were 50.9 Bcfe, with a discounted present value of
$34.6 million. Prior to designing production facilities for Habanero, we
plan to drill the South Moccasin prospect. See "Exploration and Development
Activities -- Deep Water Area," for a description of the South Moccasin
prospect.

OTHER PROPERTIES

We own various small royalty and working interests in several onshore
areas, which as of June 1, 1999 had total net proved reserves of 12.0 Bcfe with
a discounted present value of $15.6 million. Over 50% of these reserves and
their related discounted present value were attributable to our interest in the
Big Escambia Creek gas field located in south Alabama which is operated by
Exxon.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following is a summary of our anticipated drilling plans through 2000.
We continually review our drilling plans in light of changing circumstances.
Factors which may cause us to change our drilling plans are described under
"Risk Factors."

Shallow Miocene Area

We currently have an inventory of four exploration prospects in this area.
We expect to drill two of these prospects, Mobile Block 953 #2 and Mobile Block
908 #4, before year-end 1999. We currently have not scheduled any drilling
activities for the shallow Miocene area in 2000. Total estimated gross drilling
costs are estimated to be $2.1 million ($2.0 million net) and estimated gross
completion costs are $7.3 million ($6.3 million net) for these two wells.

29
<PAGE> 30

Mobile Block 953 #2. This shallow Miocene prospect is scheduled to drill in
late June 1999 in 70 feet of water. Production from the prospect will be handled
by our Mobile 864 Unit which is located nearby. Net costs to drill this prospect
will be $1.1 million. We own a 100.0% working interest in the prospect, which
will target reserve deposits at 2,250 feet. We will be the operator of this
well.

Mobile Block 908 #4. This shallow Miocene prospect is scheduled to drill in
July 1999 in 70 feet of water. The prospect is adjacent to our Mobile 864 Unit
through which production will be handled. Net costs to drill this prospect will
be $0.9 million. We own an 89.0% working interest in the prospect, which will
target reserve deposits at 2,250 feet. We will be the operator of this well.

OCS Area

We currently have an inventory of 20 exploration prospects in this area. We
expect to drill two of these prospects, Ship Shoal Block 319 and South Marsh
Island Block 261, before year-end 1999, and an additional seven prospects before
year-end 2000. Total estimated gross drilling costs are $40.6 million ($10.6
million net) and estimated gross completion costs are $204.7 million ($54.3
million net) for these nine wells.

Ship Shoal Block 319. We expect to drill a well on this prospect, located
in 300 feet of water offshore Louisiana, in the fourth quarter of 1999. Net
costs to drill this well, which is targeting reserve deposits at 9,000 feet, are
estimated to be $0.6 million. We currently own a 25.0% working interest in the
block. We are negotiating a farm-in of the remaining interest in the block under
which we would own a 100% working interest in the block and become operator.

South Marsh Island Block 261. We currently have three drilling prospects on
South Marsh Island Block 261, all of which are located in 30 feet of water. We
expect to begin drilling the first of these three wells in the fourth quarter of
1999 for estimated costs of $1.8 million per well. We own a 100.0% working
interest in and will operate these wells, but we may bring in an industry
partner and reduce our interest to approximately 50.0%. The wells will target
reserve deposits at 7,500 feet.

In addition, we drilled our "Parodi" prospect located on Main Pass Block
32, SL 16429 to a total depth of 15,305 feet and encountered a potentially
productive reservoir. Completion efforts during 1997 and 1998 encountered
mechanical difficulties. Based on additional seismic data, we plan to drill from
the existing well bore to a higher structural location in the reservoir. We
currently own a 92.4% working interest. We have not scheduled any further
drilling activities on this well as we are seeking an industry partner to
participate in the drilling operations estimated to cost $2.9 million gross. We
will operate the well and retain an approximate 50.0% working interest.

Deep Water Area

We currently have an inventory of 15 exploration prospects in this area. We
expect to drill two of these prospects, Sidewinder and Medusa, before year-end
1999 and two of these prospects, South Moccasin and Anvil, before year-end 2000.
Total estimated gross drilling costs are $84.0 million ($12.4 million net) for
these four wells. Costs to complete the wells will depend on the reserves
discovered and the decisions made by us and our partners in these prospects
regarding the appropriate production facilities to construct.

Sidewinder. Prior to designing production facilities for the Boomslang
prospect on Ewing Bank Block 994, we plan to drill the Sidewinder prospect,
located in 1,200 feet of water on Ewing Bank Block 995 and Green Canyon Blocks
24 and 25 immediately to the southeast of Boomslang. We own a 15.0% working
interest in this prospect which is scheduled to be drilled in the fourth quarter
of 1999. We are targeting reserves at a depth of approximately 16,000 feet.
Murphy is the operator of this well. Estimated net costs to drill this well are
$3.0 million.

Medusa. The Medusa prospect is located in 2,300 feet of water on
Mississippi Canyon Blocks 538 and 582. We own a 25.0% working interest in this
prospect which is scheduled to be drilled in the fourth

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<PAGE> 31

quarter of 1999. We are targeting reserves at a depth of approximately 13,000
feet. Murphy is the operator of this well. Estimated net costs to drill this
well are $4.3 million.

South Moccasin. Prior to designing production facilities for the Habanero
prospect on Garden Banks Block 341, we plan to drill the South Moccasin
prospect, located in 1,800 feet of water on Garden Banks Blocks 297 adjacent to
our Habanero discovery. We own a 12.5% working interest in this prospect which
is scheduled to be drilled in 2000. We are targeting reserves at a depth of
approximately 22,000 feet. Estimated net costs to drill this well are $2.1
million.

Anvil. Anvil is located in 5,500 feet of water on Mississippi Canyon Blocks
815/816. We own a 10.0% working interest in this prospect which is scheduled to
be drilled in 2000. We are targeting reserves at a depth of approximately 17,250
feet. Vastar is the operator of this well. Estimated net costs to drill this
well are $3.0 million.

OCS Lease Sales

In March 1999, we, along with our joint venture partners, bid on 13
deepwater blocks and were the apparent high bidder on nine blocks. Eight of the
nine blocks have been awarded. Our net cost to acquire these blocks is $3.4
million.

OIL AND GAS RESERVES

The following table sets forth certain information about our estimated net
proved reserves as of the dates set forth below. These estimates were prepared
by Huddleston & Co., Inc., our independent reserve engineers.

<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 1, ------------------------------
1999 1998 1997 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Proved developed:
Oil (Bbls)....................................... 1,988 2,079 2,976 3,385
Gas (Mcf)........................................ 83,878 76,895 88,010 49,491
Proved undeveloped:
Oil (Bbls)....................................... 11,063 4,819 426 434
Gas (Mcf)........................................ 21,095 11,135 728 933
Total proved:
Oil (Bbls)....................................... 13,051 6,898 3,402 3,819
Gas (Mcf)........................................ 104,973 88,030 88,738 50,424
Estimated future net cash flows before income taxes
(000s)........................................... $280,980 $152,552 $209,260 $216,154
======== ======== ======== ========
Discounted present value (000s).................... $173,917 $ 99,751 $136,448 $160,171
======== ======== ======== ========
</TABLE>

Huddleston & Co., Inc., our independent reserve engineers, 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 1996, 1997 and 1998 and on June 1 of 1999, without escalation,
and were otherwise prepared in accordance with the SEC 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, and 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 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

31
<PAGE> 32

estimates. Accordingly, reserve estimates are 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.

PRODUCTIVE WELLS AND DRILLING ACTIVITY

The following table sets forth the wells we drilled and completed during
the periods indicated. All but three of these wells were drilled in the federal
and state waters of the Gulf of Mexico.

<TABLE>
<CAPTION>
FIVE MONTHS YEARS ENDED DECEMBER 31,
ENDED -----------------------------------------------
JUNE 1, 1999 1998 1997 1996
------------- ------------- ------------- -------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development:
Oil........................... -- -- 2 .40 -- -- 1 .09
Gas........................... -- -- -- -- 1 1.00 2 1.52
Non-Productive................ -- -- -- -- -- -- -- --
-- ---- -- ---- -- ---- -- ----
Total................. -- -- 2 .40 1 1.00 3 1.61
== ==== == ==== == ==== == ====
Exploration:
Oil........................... 1 .11 1 .35 -- -- -- --
Gas........................... 3 1.78 3 2.14 2 1.20 1 1.00
Non-Productive................ -- -- 2 1.25 6 1.91 -- --
-- ---- -- ---- -- ---- -- ----
Total................. 4 1.89 6 3.74 8 3.11 1 1.00
== ==== == ==== == ==== == ====
</TABLE>

We owned working and royalty interests in approximately 289 gross (7.4 net)
producing oil and 316 gross (26.9 net) producing gas wells as of June 1, 1999. 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, substantially all of our wells
produce both oil and gas. At June 1, 1999, we had two gross (1.1 net)
exploratory gas wells in progress. One gross (0.2 net) in-progress well has
since been determined to be a dry hole.

LEASEHOLD ACREAGE

The following table shows our approximate developed and undeveloped (gross
and net) leasehold acreage at June 1, 1999.

<TABLE>
<CAPTION>
LEASEHOLD ACREAGE
-----------------------------------
DEVELOPED UNDEVELOPED
---------------- ----------------
LOCATION GROSS NET GROSS NET
- -------- ------- ------ ------- ------
<S> <C> <C> <C> <C>
Shallow Miocene area..................................... 87,439 75,269 22,275 18,819
OCS area................................................. 20,286 9,501 149,110 51,892
Deep water area.......................................... 11,520 2,664 115,200 20,592
Other.................................................... 8,612 4,070 4,480 2,256
------- ------ ------- ------
Total.......................................... 127,857 91,504 291,065 93,559
======= ====== ======= ======
</TABLE>

As of June 1, 1999, we also owned various royalty and overriding royalty
interests in 1,336 net developed acres and 6,862 net undeveloped acres. In
addition, we owned 5,464 net developed and 134,536 net undeveloped mineral
acres. Since June 1, 1999, we have acquired an additional 5,760 gross (1,152
net) undeveloped acres in our deep water area.

MAJOR CUSTOMERS

For the year ended December 31, 1998, Dynegy Marketing & Trade, PG&E Energy
Trading Corp., and Columbia Energy Services purchased 23%, 26% and 22%,
respectively, of our natural gas and oil production. All three customers
purchased production primarily from Callon-owned interests in federal outer
continental shelf leases, Chandeleur Block 40, Main Pass 163, Main Pass 164/165,
Mobile

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<PAGE> 33

Block 864 and Mobile Block 952/955 fields. Because of the nature of oil and gas
operations and the marketing of production, we believe that the loss of these
customers would not have a significant adverse impact on our ability to sell our
production.

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:

- royalty interests and other burdens under oil and gas leases;

- 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;

- interests which entitle a person to receive a portion of our production
after we have received a specified amount of production;

- 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; and

- 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.

CORPORATE OFFICES

Our headquarters are located in Natchez, Mississippi, in approximately
51,500 square feet of owned space. 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 as alternative locations to our leased space are
anticipated to be readily available.

EMPLOYEES

We had 109 employees as of March 31, 1999, none of whom are currently
represented by a union. We believe that we have good relations with our
employees. We employ eight petroleum engineers and four petroleum geoscientists.

LITIGATION

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.

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<PAGE> 34

FEDERAL REGULATIONS

Our operations are subject to regulation by federal and state government.
These regulations apply to:

- the sale and transportation of oil and gas we produce;

- the conduct of our operations on federal, state and Indian leases; and

- the effect our operations may have on the environment.

Each of these categories is discussed below.

Sales and Transportation of Oil and Gas. Prior to January 1, 1993, prices
for natural gas were subject to extensive regulation by the federal government.
Effective January 1, 1993, the federal government repealed these regulations.
Thus, we can sell all of our gas production at market prices, subject to
applicable contract provisions.

The rates, terms and conditions applicable to the interstate transportation
of natural gas by pipelines are regulated by the Federal Energy Regulatory
Commission ("FERC").

Historically, large interstate natural gas pipelines would purchase gas
supplies from producers in the field and would sell to local distributors and
industrial customers under long-term contracts. Because the pipelines controlled
the market for natural gas, producers could not get their product to the market,
and the market could not buy gas direct from the producers without going through
the pipelines. Since 1985, the FERC has implemented regulations intended to
increase competition and make natural gas transportation, including
transportation offshore, more accessible to gas buyers and sellers by requiring
pipelines to separate or "unbundle" their transportation services from their
activities in buying and selling natural gas.

On April 26, 1992, the FERC promulgated Order 636, an extensive set of
regulations requiring all interstate pipelines to restructure their services.
The intent of Order 636 is to provide equal access and transportation services
for all gas supplies from all regulated pipelines. Order 636 has fostered robust
competition among all facets of the natural gas transportation industry by and
among producers, transporters, marketers and consumers.

While Order 636 does not directly regulate natural gas producers such as
Callon, it does affect how we get our production to market. The courts have
largely affirmed the significant features of Order 636 and numerous related
orders pertaining to the individual pipelines, although certain appeals remain
pending and the FERC continues to review and modify the regulations. In
particular, the FERC has recently begun a broad review of its transportation
regulations, including:

- how its regulations operate in conjunction with state proposals for
retail gas marketing restructuring;

- whether to eliminate cost-of-service based rates for short-term
transportation;

- whether to allocate all short-term capacity on the basis of competitive
auctions; and

- whether changes to its long-term transportation service policies may be
appropriate to avoid a market bias toward short-term contracts.

We do not believe that we will be affected by any action taken by the
courts or by the FERC materially differently than other natural gas producers
and marketers with which we compete.

Although to date the FERC has imposed light-handed regulation on off-shore
gathering facilities, it has the authority to exercise jurisdiction over
gathering facilities, if necessary, to permit non-discriminatory access to
service. Much of our production comes from the OCS, and we rely upon our own gas
gathering facilities as well as gas gathering services provided by others, both
of which could be subject to FERC scrutiny in the future.

We can sell crude oil and condensate at market prices not subject at this
time to price controls. The price that we receive from the sale of these
products will be affected by its quality and the cost of

34
<PAGE> 35

transporting the products to market. The rates, terms, and conditions applicable
to the interstate transportation of oil and related products by pipelines are
also regulated by the FERC. In 1995, the FERC implemented rules that provide a
simplified, generally applicable method of regulating oil pipeline rates by use
of an index for setting rate ceilings. We do not believe that these rules affect
us any differently than other producers and marketers with which we compete.
With respect to the transportation of oil and condensate offshore in federal
waters, the FERC requires that all pipelines provide open and non-
discriminatory access to both owner and non-owner shippers.

Federal, State or Indian Leases. In the event we conduct operations on
federal, state or Indian oil and gas leases (including our offshore leases), our
operations must comply with numerous regulatory restrictions, including various
nondiscrimination statutes and royalty requirements. In addition, we must obtain
permits issued by the Bureau of Land Management ("BLM") or Minerals Management
Service ("MMS") or other appropriate federal or state agencies to conduct our
operations offshore or onshore on federal or Indian lands.

Federal leases, in addition to relatively standard terms, require
compliance with detailed MMS and BLM regulations and orders, which are subject
to change. In addition to permits required by other federal agencies (such as
the Coast Guard, the Army Corps of Engineers and the Environmental Protection
Agency), lessees must obtain a permit from the MMS or BLM prior to commencement
of offshore or onshore drilling. The MMS has promulgated regulations requiring
offshore production facilities to meet stringent engineering and construction
specifications. The MMS also has regulations restricting the flaring or venting
of natural gas, and has proposed to amend such regulations to prohibit the
flaring of liquid hydrocarbons and oil without prior authorization. Similarly,
the MMS has approved other regulations governing plugging and various
obligations of offshore lessees, and the MMS generally requires that lessees
have a substantial net worth or post bonds or other acceptable assurances that
such obligations will be met. Under certain circumstances, the MMS may require
the suspension or termination of any of our operations on federal leases. Any
such suspension or termination could materially and adversely affect our
financial condition, cash flows and operations.

The Mineral Leasing Act of 1920 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 provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect. We
own interests in numerous federal onshore oil and gas leases. Because we are a
publicly-traded company with limited control over the ownership of our equity
interests, it is possible that holders of our equity interests may be citizens
of foreign countries which at some time in the future might be determined to be
non-reciprocal.

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. In addition, the rates which we can charge for gas
produced, consumed and transported in any one state, the transportation of gas
in the state, and the costs of construction and operation of a pipeline in the
state may be impacted by state rules and regulations. The impact of such
requirements and regulations would not be any more adverse to us than they would
be to other similar owners or operators conducting business in the state.

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<PAGE> 36

ENVIRONMENTAL REGULATIONS

General. Our activities are subject to existing federal, state and local
environmental laws and regulations. These laws and regulations govern the
environmental condition of properties, the disposal and release of production
wastes, oil spills, air emissions and occupational safety.

- Environmental Condition of Properties. We own or lease numerous
properties that have been used for production of oil and gas for many
years. Although we have utilized operating and disposal practices
standard in the industry at the time, hydrocarbons or other solid wastes
or hazardous wastes may have been disposed or released on or under these
properties. In addition, many of these properties have been operated by
third parties. We have had no control over treatment by third parties of
hydrocarbons or other solid wastes and the manner in which they disposed
of or released these substances. State and federal laws applicable to oil
and gas wastes and properties have gradually become stricter over time
and will most likely continue to place further restrictions on oil and
gas field operations. Under any such new laws, we could be required to
remove or remediate previously disposed wastes (including wastes disposed
or released by prior owners or operators) or property contamination
(including groundwater contamination by prior owners or operators). We
could also be required to perform remedial plugging operations to prevent
future contamination.

- Production Wastes. We generate wastes, including hazardous wastes, that
are subject to the federal Resource Conservation and Recovery Act
("RCRA") and comparable state laws. It is possible that wastes generated
by our oil and gas operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes"
under RCRA or comparable state laws. Any designation of these currently
exempt wastes as "hazardous wastes" would subject our wastes to more
rigorous and costly disposal requirements.

Our operations are also potentially subject to the federal Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"), which
imposes liability without regard to fault or legality of the original
conduct on persons for a release of a "hazardous substance" into the
environment. These persons include the owner and operator of a site and
persons that disposed or arranged for the disposal of the hazardous
substances found at a site. Persons found responsible under CERCLA may be
liable for the costs of actions conducted at sites by the U.S.
Environmental Protection Agency and, in some cases, third parties in
response to threats to the public or environment. Neither Callon nor its
predecessors have been designated as a potentially responsible party by
the EPA under CERCLA with respect to any such site.

- Oil Pollution. There are a variety of regulations imposed on "responsible
parties" related to the prevention of oil spills and liability for
damages resulting from such spills in United States waters, including the
Oil Pollution Act of 1990 (the "OPA"). A "responsible party" includes the
lessee or permittee of an offshore lease and the owner or operator of
associated drilling and production platforms. Liability is assigned to
each responsible party for oil removal costs and a variety of public and
private damages. While liability limits apply in some circumstances, few
defenses exist to the liability imposed by the OPA.

We are required to provide evidence of financial ability under the OPA
and recently adopted MMS rules to cover potential liabilities associated
with a potential spill. The OPA and MMS rules require responsible parties
for offshore facilities in the OCS and in some state waters that have a
worst case oil spill potential of more than 1,000 barrels to provide
financial assurance in amounts of $35 million under OPA rules and $10
million under MMS rules. This financial assurance amount may be increased
to $150 million if warranted by specific risks posed by the operations or
if the worst case oil spill potential at the facility exceeds regulatory
threshold levels. We currently comply with these OPA and MMS requirements
and do not anticipate that we will experience difficulty in satisfying
any future requirements for demonstrating financial responsibility.

- Air Emissions. Our operations are subject to local, state and federal
laws and regulations for the control of emissions from sources of air
pollution. Failure to comply strictly with air laws,

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<PAGE> 37

regulations or permits generally may result in the payment of monetary
fines and correction of any identified deficiencies. Alternatively,
regulatory agencies could require that we temporarily or permanently
cease production operations at specific facilities or that we forego
construction or operation of certain air emission sources. We believe
that in such cases we would have enough existing capacity to continue our
operations without a material adverse effect on any particular producing
field.

- OSHA. Our operations are subject to worker safety and health requirements
under the federal Occupational Safety and Health Act and comparable state
laws. Under these laws, we are required to organize and/or disclose
information about hazardous materials used or produced in our operations.
Certain of this information must be provided to employees, state and
local governmental authorities and local citizens.

We believe that absent the occurrence of an extraordinary event, compliance
with existing laws and regulations relating to the protection of the environment
will not have a material effect upon our capital expenditures, earnings or
existing assets and operations. We cannot predict what effect additional
environmental regulation, legislation or enforcement policies, and claims for
damages resulting from our operations could have on our activities. Although we
believe that compliance with environmental regulations will not have a material
adverse effect, risks of substantial costs and liabilities are inherent in oil
and gas production operations, and we cannot assure you that significant costs
and liabilities will not be incurred. Moreover, it is possible that other
developments, such as stricter or reinterpreted 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 Callon.
We cannot predict what proposals, if any, might actually be enacted by Congress
or the various state legislatures and what effect, if any, these proposals might
have on our operations.

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<PAGE> 38

MANAGEMENT

Our certificate of incorporation currently provides for a board of
directors divided into three classes of nearly equal size, designated as Class
I, Class II and Class III. Directors are elected to serve three-year terms.

INFORMATION ABOUT OUR DIRECTORS AND EXECUTIVE OFFICERS

The following is information about our directors and executive officers.

<TABLE>
<CAPTION>
POSITION
NAME AGE SINCE PRESENT POSITION
- ---- --- -------- ----------------
<S> <C> <C> <C>
John S. Callon........................ 79 1994 Director, Class II; Chairman of the
Board
Fred L. Callon........................ 49 1994 Director, Class III; President; Chief
Executive Officer
Dennis W. Christian................... 52 1994 Director, Class III; Senior Vice
President; Chief Operating Officer
John S. Weatherly..................... 47 1994 Senior Vice President and Chief
Financial Officer
James O. Bassi........................ 45 1997 Vice President; Controller
Thomas E. Schwager.................... 48 1997 Vice President
H. Michael Tatum...................... 70 1994 Vice President; Secretary
Kathy G. Tilley....................... 53 1996 Vice President
Stephen F. Woodcock................... 47 1997 Vice President
Rodger W. Smith....................... 50 1999 Treasurer
Leif Dons............................. 49 1999 Director, Class II
Robert A. Stanger..................... 59 1995 Director, Class I
John C. Wallace....................... 60 1994 Director, Class I
B. F. Weatherly....................... 55 1994 Director, Class II
Richard O. Wilson..................... 69 1995 Director, Class I
</TABLE>

The following is a brief description of the background and principal
occupation of each director and executive officer:

JOHN S. CALLON is our Chairman of the Board of Directors. Effective January
2, 1997, John S. Callon resigned as our Chief Executive Officer, a position he
had held since 1980. Mr. Callon founded our company in 1950, and has held an
executive office with us since that time. He has served as a director of the
Mid-Continent Oil and Gas Association and as the President of the Association's
Mississippi-Alabama Division. He has also served as Vice President for
Mississippi of the Independent Petroleum Association of America. He is a member
of the American Petroleum Institute. Mr. Callon is the uncle of Fred L. Callon.

FRED L. CALLON is our President and Chief Executive Officer. Prior to
January 1997, he was our President and Chief Operating Officer, a position which
he had held since 1984. Before that, he was employed by us in various positions
since 1976. He graduated from Millsaps College in 1972 and received his M.B.A.
degree from the Wharton School of Finance in 1974. Following graduation and
before joining us, he was employed by Peat, Marwick, Mitchell & Co., certified
public accountants. He is a certified public accountant and is a member of the
American Institute of Certified Public Accountants and the Mississippi Society
of Certified Public Accountants. He is the nephew of John S. Callon.

DENNIS W. CHRISTIAN is our Senior Vice President and Chief Operating
Officer. Prior to January 1997, he was our Senior Vice President of Operations
and Acquisitions and had held that or similar positions with us since 1981.
Prior to joining us, he was resident manager in Stavanger, Norway for Texas
Eastern Transmission Corporation. Mr. Christian received his B.S. degree in
petroleum engineering in 1969 from Louisiana Polytechnic Institute. His previous
experience includes five years with Chevron U.S.A. Inc.

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<PAGE> 39

JOHN S. WEATHERLY is our Senior Vice President and Chief Financial Officer.
Prior to April 1996, he was our Vice President, Chief Financial Officer and
Treasurer and had held those positions since 1983. Prior to joining us in 1980,
he was employed by Arthur Andersen LLP as audit manager in the Jackson,
Mississippi office. He received his B.B.A. degree in accounting in 1973 and his
M.B.A. degree in 1974 from the University of Mississippi. He is a certified
public accountant and a member of the American Institute of Certified Public
Accountants and the Mississippi Society of Certified Public Accountants. John S.
Weatherly and B. F. Weatherly are brothers.

JAMES O. BASSI is our Vice President and Controller. Prior to being
appointed to that position in November 1997, he was our Corporate Controller
from June 1997 and prior thereto was our Manager of the accounting department of
Callon and Callon Petroleum Operating. Mr. Bassi has been employed by Callon and
its predecessors for over ten years. Prior to his employment with us, he was
employed by Arthur Andersen LLP. He received his B.S. degree in accounting in
1976 from Mississippi State University. He is a member of the American Institute
of Certified Public Accountants and the Mississippi Society of Certified Public
Accountants.

THOMAS E. SCHWAGER is our Vice President of Engineering and Operations.
Prior to being appointed to that position in November 1997, he had held
engineering positions with us since 1981. Prior to joining us, Mr. Schwager held
various engineering positions with Exxon Company USA in Louisiana and Texas. He
received his B.S. degree in petroleum engineering from Louisiana State
University in 1972. He is a registered professional engineer in the state of
Louisiana and is a member of the Society of Petroleum Engineers.

H. MICHAEL TATUM is our Vice President and Secretary, and is responsible
for management of administrative matters. Mr. Tatum has held this position with
us since 1969. He graduated from Southern Methodist University in 1967 and is a
member of the American Society of Corporate Secretaries and the Society for
Human Resource Management.

KATHY G. TILLEY is our Vice President of Acquisitions and New Ventures, a
position she has held since April 1996. She was first employed by us in December
1989 as manager of acquisitions and prior thereto, held that or similar
positions as a consultant to us since 1981. Ms. Tilley received her B. A. degree
in economics from Louisiana State University in 1967.

STEPHEN F. WOODCOCK is our Vice President of Exploration. He was appointed
to that position in November 1997. He has been employed by us since 1995,
serving as manager of geology and geophysics. Before that, he was manager of
geophysics for CNG Producing Company and division geophysicist for Amoco
Production Company. Mr. Woodcock received his Masters degree in geophysics from
Oregon State University in 1975.

RODGER W. SMITH is our Treasurer. Prior to being appointed to that position
in April, 1999, he was our Manager of Budget and Analysis. Before that, Mr.
Smith was Manager of exploration and production accounting and has been employed
by Callon and its predecessors since 1983. Prior to his employment with us, he
was employed by International Paper Company as a plant controller. He received
his B.S. degree in accounting from the University of Southern Mississippi in
1973.

LEIF DONS has since 1997 been Senior Vice President, Business Development
of Fred. Olsen Energy ASA, a publicly held Norwegian company engaged in the
offshore energy service industry. From 1992 until 1997, Mr. Dons was employed by
Kvaerner ASA in various positions, including the fields of international
operations and the commercialization of new technology, and as resident country
manager responsible for Israel and Palestine. From 1983 until 1991, he served as
the managing director of Norwegian Oil Consortium A/S & Co., an oil company with
producing properties in Norway. He negotiated the sale of that company in 1991.
From 1973 until 1983, Mr. Dons held various positions as an analyst, staff
engineer and economist at the Pulp and Paper Research Institute, Norway and Saga
Petroleum ASA. Mr. Dons received a Master of Science degree in engineering from
the Norwegian Institute of Technology in 1973.

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<PAGE> 40

ROBERT A. STANGER has been the managing general partner since 1978 of
Robert A. Stanger & Company, Inc., a Shrewsbury, New Jersey-based firm engaged
in publishing financial material and providing investment banking services to
the real estate and oil and gas industries. He is a director of Citizens
Utilities, Stamford, Connecticut, a provider of telecommunications, electric,
gas, and water services and Electric Lightwaves, Inc., Seattle, Washington, a
regional fiber optic telephone company. Previously, Mr. Stanger was Vice
President of Merrill Lynch & Co. He received his B.A. degree in economics from
Princeton University in 1961. Mr. Stanger is a member of the National
Association of Securities Dealers and the New York Society of Security Analysts.

JOHN C. WALLACE is a Chartered Accountant having qualified with Coopers and
Lybrand in Canada in 1963, after which he joined Baring Brothers & Co., Limited
in London, England. For more than the last eleven years, he has served as
Chairman of Fred. Olsen Ltd., a London-based corporation which he joined in
1968, and which specializes in the business of shipping and property
development. He is a director of Fred. Olsen Energy ASA, a publicly held
Norwegian service company engaged in the offshore energy service industry;
Harland & Wolff PLC, Belfast, a shipbuilding yard for the offshore oil and gas
industry; and Ganger Rolf ASA and Bonheur ASA, Oslo, both publicly-traded
shipping companies. He is also an executive officer of NOCO Management, Ltd., a
general partner of NOCO Enterprises, L.P. and of other companies associated with
Fred. Olsen Interests.

B. F. WEATHERLY is a principal of Amerimark Capital Group, Houston, Texas,
an investment banking firm and a general partner of CapSource Fund, L. P.,
Jackson Mississippi, an investment fund. He is an executive officer of NOCO
Management Ltd., the general partner of NOCO Enterprises, L.P. Prior to
September 1996, he was Executive Vice President, Chief Financial Officer and a
director of Belmont Constructors, Inc., a Houston, Texas-based industrial
contractor formerly associated with Fred. Olsen Interests. He holds a Master of
Accountancy degree from University of Mississippi. He has previously been
associated with Arthur Andersen LLP, and has served as a Senior Vice President
of Weatherford International, Inc. B. F. Weatherly and John S. Weatherly are
brothers.

RICHARD O. WILSON is an Offshore Consultant. In his 42 years of working in
offshore drilling and construction, he spent two years with Zapata Offshore and
21 years with Brown & Root, Inc. working in various managerial capacities in the
Gulf of Mexico, Venezuela, Trinidad, Brazil, the Netherlands, the United Kingdom
and Mexico. He was a director and senior group vice president of Brown & Root,
Inc. and senior vice president of Halliburton, Inc. For the last 18 years he has
been associated with the Fred. Olsen Interests where he served as Chairman of
OGC International PLC, Dolphin A/S and Dolphin Drilling Ltd., and Belmont
Constructors, Inc. Since the sale of OGC International PLC to Halliburton, Inc.
in 1997, he has been a consultant to Brown & Root, Inc. on oil and gas projects
in Brazil, Bolivia, Mexico and Ecuador. He holds a B.S. degree in civil
engineering from Rice University. Mr. Wilson is a Fellow in the American Society
of Civil Engineers and a member of the Institute of Petroleum, London, England.

All of our officers and directors are United States citizens, except Mr.
Wallace, who is a citizen of Canada, and Mr. Dons, who is a citizen of Norway.

BENEFICIAL OWNERSHIP OF OUR COMMON AND PREFERRED STOCK

The following table shows the ownership of our common stock and series A
preferred stock by the following:

- our five most highly compensated executive officers;

- all of our directors;

- all of our executive officers and directors as a group; and

- anyone who is known by us to beneficially own 5% or more of our
outstanding common stock or preferred stock;

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<PAGE> 41

Based on SEC rules, shares of common stock which an individual or group has
the right to acquire within 60 days pursuant to the exercise of options or
warrants are deemed to be outstanding for the purpose of computing the
percentage ownership of such individual or group. These shares are not deemed to
be outstanding for the purpose of computing the percentage ownership of any
other person show on this table.

Unless otherwise indicated, each person named in the following table has
the sole power to vote and dispose of the shares listed next to their name.
Information in the tables and accompanying text has been obtained from filings
made with the SEC or, in the case of our directors and executive officers, has
been provided by such individuals. Unless otherwise indicated, the information
provided below is based on information available to us as of May 15, 1999.

<TABLE>
<CAPTION>
COMMON STOCK PREFERRED STOCK
---------------------- ----------------------
NAME AND ADDRESS NUMBER OF NUMBER OF
OF BENEFICIAL OWNERS SHARES PERCENTAGE SHARES PERCENTAGE
- -------------------- --------- ---------- --------- ----------
<S> <C> <C> <C> <C>
EXECUTIVE OFFICERS:
John S. Callon.................................. 298,902 3.46% 0 --
Fred L. Callon.................................. 791,346 9.10% 0 --
Dennis W. Christian............................. 161,185 1.86% 0 --
John S. Weatherly............................... 149,660 1.73% 0 --
Thomas E. Schwager.............................. 47,652 * 0 --
Kathy G. Tilley................................. 102,980 1.19% 0 --
NON-EMPLOYEE DIRECTORS:
Leif Dons....................................... 0 -- 0 --
Robert A. Stanger............................... 40,856 * 0 --
John C. Wallace................................. 2,004,779 23.35% 0 --
B.F. Weatherly.................................. 147,664 1.72% 0 --
Richard O. Wilson............................... 68,877 * 1,000 *
ALL DIRECTORS AND EXECUTIVE OFFICERS AS A GROUP
(15 PERSONS).................................... 3,845,438 40.82% 1,000 *

CERTAIN BENEFICIAL OWNERS:
Fred. Olsen Energy ASA.......................... 1,839,386 21.52% 0 --
Fred. Olsensgate 2
0152 Oslo, Norway
State Street Research & Management Company...... 827,400 9.68% 0 --
One Financial Center, 30th Floor
Boston, Massachusetts 02111-2690
The Guardian Life Insurance Company of
America...................................... 748,060 8.27% 220,000 21.04%
201 Park Avenue South
New York, New York 10003
Brinson Partners, Inc........................... 554,000 6.48% 0 --
209 South LaSalle
Chicago, Illinois 60604-1295
UBS AG.......................................... 554,000 6.48% 0 --
Bahnhofstrasse 45
8021, Zurich, Switzerland
Dimensional Fund Advisors Inc................... 505,800 5.92% 0 --
1299 Ocean Avenue, 11th Floor
Santa Monica, California 90401
</TABLE>

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

* Under 1%.

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<PAGE> 42

JOHN S. CALLON. The shares beneficially owned by John S. Callon include
105,000 shares held in a family limited partnership and 90,000 shares subject to
options under our 1994 Stock Incentive Plan. The shares beneficially owned by
John S. Callon do not include 58,501 shares owned by John S. Callon's wife over
which he disclaims beneficial ownership. NOCO Enterprises, L.P. Fred. Olsen
Energy ASA and Fred. Olsen Ltd. as of May 15, 1999, owned 107,297, 1,839,386 and
14,971 shares of common stock, respectively. John S. Callon, who is party to an
agreement regulating the voting and transfer of common shares with NOCO
Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. disclaims
beneficial ownership of the NOCO Enterprises, L.P. Fred. Olsen Energy ASA and
Fred. Olsen Ltd. shares.

FRED L. CALLON. The shares beneficially owned by Fred L. Callon include
268,012 shares held as custodian for certain minor Callon family members; 78,430
shares held as trustee of certain Callon family trusts; 57,442 shares held as
trustee of shares held by the Callon Petroleum Company Employee Savings and
Protection Plan; 80,000 shares subject to options under our 1994 Stock Incentive
Plan and 75,000 shares subject to options under our 1996 Stock Incentive Plan.
The shares beneficially owned by Fred L. Callon do not include 25,037 shares
owned by Fred L. Callon's wife over which he disclaims beneficial ownership.
NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd., as of May
15, 1999, owned 107,297, 1,839,386 and 14,971 shares of common stock,
respectively. Fred L. Callon, who is party to an agreement regulating the voting
and transfer of common shares with NOCO Enterprises, L.P., Fred. Olsen Energy
ASA and Fred. Olsen Ltd. disclaims beneficial ownership of the NOCO Enterprises,
L.P., Fred. Olsen Energy ASA and Fred. Olsen Ltd. shares. Mr. Callon's address
is 200 North Canal Street, P.O. Box 1287, Natchez, Mississippi 39120.

DENNIS W. CHRISTIAN. The shares beneficially owned by Dennis W. Christian
include 60,000 shares subject to options under our 1994 Stock Incentive Plan and
69,500 shares subject to options under our 1996 Stock Incentive Plan.

JOHN S. WEATHERLY. The shares beneficially owned by John S. Weatherly
include 217 shares held as custodian for his minor children; 60,000 shares
subject to options under our 1994 Stock Incentive Plan and 61,500 shares subject
to options under our 1996 Stock Incentive Plan.

THOMAS E. SCHWAGER. The shares beneficially owned by Thomas E. Schwager
include 20,000 shares subject to options under our 1994 Stock Incentive Plan and
13,200 shares subject to options under our 1996 Stock Incentive Plan.

KATHY G. TILLEY. The shares beneficially owned by Kathy G. Tilley include
30,000 shares subject to options under our 1994 Stock Incentive Plan and 48,000
shares subject to options under our 1996 Stock Incentive Plan.

ROBERT A. STANGER. The shares beneficially owned by Robert A. Stanger
include 20,000 shares subject to options under our 1994 Stock Incentive Plan and
20,000 shares subject to options under our 1996 Stock Incentive Plan.

JOHN C. WALLACE. The shares beneficially owned by John C. Wallace include
107,297 shares owned by NOCO Enterprises, L.P.; 14,971 shares owned by Fred.
Olsen Ltd.; 1,839,386 shares owned by Fred. Olsen Energy ASA; 20,000 shares
subject to options under our 1994 Stock Incentive Plan and 20,000 shares subject
to options under our 1996 Stock Incentive Plan. See "Fred. Olsen Energy ASA"
below. Mr. Wallace's address is 65 Vincent Square, London, SW1P 2RX, England.

B.F. WEATHERLY. The shares beneficially owned by B.F. Weatherly include
107,297 shares owned by NOCO Enterprises, LP; 20,000 shares subject to options
under our 1994 Stock Incentive Plan and 20,000 shares subject to options under
our 1996 Stock Incentive Plan. See "Fred. Olsen Energy ASA" below.

RICHARD O. WILSON. The shares beneficially owned by Richard O. Wilson
include 26,604 shares held in a family limited partnership; 2,273 shares
issuable upon conversion of 1,000 shares of series A preferred stock held in the
family partnership; 20,000 shares subject to options under our 1994 Stock
Incentive Plan and 20,000 shares subject to options under our 1996 Stock
Incentive Plan.

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<PAGE> 43

ALL DIRECTORS AND EXECUTIVE OFFICERS. The shares beneficially owned by all
of our directors and executive officers as a group include 465,000 shares
subject to options under our 1994 Stock Incentive Plan exercisable within 60
days; 408,700 shares subject to options under our 1996 Stock Incentive Plan
exercisable within 60 days; and 148,203 shares awarded as performance shares or
restricted stock which vested in February, 1999.

FRED. OLSEN ENERGY ASA. The following information and the information in
the foregoing table is based on information disclosed on a Schedule 13D dated
August 20, 1997 and as otherwise disclosed to us by Fred. Olsen Energy ASA.
Fred. Olsen Energy ASA has the sole power to vote and the sole power to dispose
of 1,839,386 shares of our common stock. Ganger Rolf ASA, a public joint stock
company organized and existing under the laws of the Kingdom of Norway and the
owner of 28.81% of the outstanding capital stock of Fred. Olsen Energy ASA and
Bonheur ASA, a public joint stock company organized and existing under the laws
of the Kingdom of Norway and the owner of 28.81% of the outstanding capital
stock of Fred. Olsen Energy ASA, together have the power to direct the vote and
disposition of the shares of our common stock owned by Fred. Olsen Energy ASA.
AS Quatro, a joint stock company organized and existing under the laws of the
Kingdom of Norway and the owner of 1.66% of the outstanding capital stock of
Ganger Rolf ASA and 42.10% of the outstanding capital stock of Bonheur ASA and
AS Cinco, a joint stock company organized and existing under the laws of the
Kingdom of Norway and the owner of 11.99% of the outstanding capital stock of
Ganger Rolf ASA, each disclaims beneficial ownership of the shares of our common
stock owned by Fred. Olsen Energy ASA. John C. Wallace, one of our directors, is
a director of Fred. Olsen Energy ASA and a director of Ganger Rolf ASA, Bonheur
ASA, AS Quatro and AS Cinco and, as a result, may by deemed to share the power
to vote and dispose of, and therefore be a beneficial owner of the shares of
common stock owned by Fred. Olsen Energy ASA. The principal business address and
principal executive offices of Ganger Rolf ASA, Bonheur ASA, AS Quatro and AS
Cinco are located at Fred. Olsensgate 2, 0152 Oslo, Norway.

STATE STREET RESEARCH & MANAGEMENT COMPANY. The following information and
the information in the foregoing table is based upon a Schedule 13G, filed with
the SEC on February 8, 1999 by State Street Research & Management Company. State
Street Research & Management Company has sole voting power with respect to
700,400 shares of common stock and sole dispositive power with respect to all of
the shares it beneficially owns.

THE GUARDIAN LIFE INSURANCE COMPANY OF AMERICA. The following information
and the information in the foregoing table is based upon a Schedule 13G/A, filed
with the SEC on February 11, 1998, by The Guardian Life Insurance Company of
America and certain of its affiliates. The common stock beneficially owned by
The Guardian Life Insurance Company of America includes 500,060 shares issuable
upon conversion of 220,000 shares of series A preferred stock.

BRINSON PARTNERS, INC. The following information and the information in the
foregoing table is based on a Schedule 13G, filed with the SEC on February 11,
1999, by UBS AG and Brinson Partners, Inc. Both UBS AG and Brinson Partners,
Inc. possess shared voting and dispositive power with respect to the shares
beneficially owned by them.

DIMENSIONAL FUND ADVISORS INC. The information in the foregoing table is
based upon a Schedule 13G, filed with the SEC on February 11, 1999, by
Dimensional Fund Advisors Inc.

STOCKHOLDERS' AGREEMENT

In connection with the formation of Callon in 1994, certain members of the
Callon family (including John S. Callon and Fred L. Callon) and NOCO
Enterprises, L.P. entered into a stockholders' agreement, which was subsequently
amended to include Fred. Olsen Energy ASA and Fred. Olsen Ltd. Under the
stockholders' agreement, which is dated September 16, 1994, the members of the
Callon family, on the one hand and NOCO Enterprises, L.P., Fred. Olsen Energy
ASA and Fred. Olsen Ltd. on the other hand, each elect two directors to Callon's
board of directors. Specifically, in the stockholders' agreement, the members of
the Callon family, NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred.
Olsen Ltd. agree to use their best efforts, including voting the shares of
common stock which they own, to cause
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<PAGE> 44

Callon's board of directors to be composed of at least four members. Two of
these members are selected by the members of the Callon family and two of these
members are selected by NOCO Enterprises, L.P., Fred. Olsen Energy ASA and Fred.
Olsen Ltd. The stockholders' agreement also contains restrictions on transfer of
shares of common stock owned by the members of the Callon family, NOCO
Enterprises, L.P. Fred. Olsen Energy ASA and Fred. Olsen Ltd. and prohibits the
members of the Callon family, NOCO Enterprises, L.P., Fred. Olsen Energy ASA and
Fred. Olsen Ltd. from taking certain actions which would result in certain
changes of control or fundamental changes, without the consent of the other
party. The Callon family, NOCO Enterprises, L.P., Fred. Olsen Energy ASA and
Fred. Olsen Ltd. own an aggregate of 43.34% of our common stock.

DESCRIPTION OF THE NOTES

We will issue the 10.25% Senior Subordinated Notes due 2004 under an
indenture between us and American Stock Transfer & Trust Company, as trustee.
The following description is a summary of selected provisions of the indenture
and the notes. We have not restated the indenture in its entirety. We filed the
form of the indenture as an exhibit to our registration statement. You should
read the indenture because the indenture, and not this description, will control
your rights as a holder of the notes. You can find the definitions of certain
terms used in this description under the subheading "Certain Definitions."
Unless otherwise specifically noted in the following discussion, references to
"Callon," "we" or "us" means Callon Petroleum Company without its Subsidiaries.
In the summary below, we have included references to the applicable section
numbers of the indenture so that you can easily locate these provisions.
Capitalized terms used in the summary have the meanings specified in the
indenture.

The notes represent our direct unsecured obligations and rank equally with
all our existing senior subordinated notes. The notes are subordinated to our
Senior Indebtedness as discussed under the subheading "Subordination" and are
structurally subordinated to all liabilities of our Subsidiaries. Assuming we
had issued the notes and applied the proceeds as intended as of March 31, 1999,
we would have had $100.2 million of Senior Indebtedness. As of March 31, 1999,
our Subsidiaries had liabilities of $12.0 million, excluding guarantees of
Senior Indebtedness. The indenture will permit us to incur additional Senior
Indebtedness subject only to certain limitations described under the subheading
"Certain Covenants -- Incurrence of Indebtedness." Our Credit Facility
constitutes Senior Indebtedness. All indebtedness under our Credit Facility is
secured by substantially all of our and our Subsidiaries' producing oil and gas
properties.

As of the date of the indenture, all of our Subsidiaries will be
"Restricted Subsidiaries." However, under the circumstances described in the
definition of "Unrestricted Subsidiaries," located under the subheading "Certain
Definitions," we will be permitted to designate certain of our Subsidiaries as
"Unrestricted Subsidiaries." Unrestricted Subsidiaries will not be subject to
many of the restrictive covenants in the indenture.

PRINCIPAL, INTEREST, AND MATURITY OF THE NOTES

We will issue notes with a maximum aggregate principal amount of
$40,000,000. The notes will mature on September 15, 2004, unless we elect to
redeem them earlier.

Interest on the notes will accrue at the rate of 10.25% per annum, and we
will pay interest quarterly on the 15th day of March, June, September and
December, commencing on September 15, 1999. We will make each interest payment
to the holders of record of the notes on the 1st day of March, June, September
and December immediately preceding such interest payment. Interest on the notes
will accrue from the date of original issuance and, thereafter, from the date we
most recently paid interest.

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<PAGE> 45

REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND PRINCIPAL

Book-Entry Notes

We will issue the notes in the form of a global note that will be deposited
with The Depository Trust Company, New York, New York ("DTC"). This means that
we will not issue certificates to each holder. One global note will be issued to
DTC which will keep an electronic record of its participants whose clients have
purchased the notes. The participant will then keep a record of its clients who
purchased the notes. Unless a global note is exchanged in whole or in part for a
certificated note, a global note may not be transferred; except that DTC, its
nominees, and their successors may transfer a global note as a whole to one
another.

DTC and its participants will show beneficial interests in and make
transfers of beneficial interests in global notes only through their records.
We, the trustee and the paying agent will not maintain, review or supervise
these records. [Sections 308 and 312] The laws of some states require that
certain persons take physical delivery in definitive form of securities which
they own. If these laws apply, they may limit the ability to transfer beneficial
interests in the global note.

DTC will hold the notes through its nominee, Cede & Co. We will wire
principal and interest payments either directly to Cede & Co. or to the trustee
or other paying agent for payment to Cede & Co. We, the trustee and the paying
agent will treat Cede & Co. as the owner of the global notes for all purposes
and will have no direct responsibility if Cede & Co. fails to distribute those
payments to owners of beneficial interest in the global notes. [Section 308]

It is DTC's current practice, upon receipt of any payment of principal or
interest, to credit participants' accounts on the payment date according to
their holdings of beneficial interests in the global notes as shown on DTC's
records. In addition, it is DTC's current practice to assign any consenting or
voting rights to participants whose accounts are credited with notes on a record
date by using an omnibus proxy. Customary practices between participants and
owners of beneficial interests will govern payments by participants to owners of
beneficial interests in the global notes and voting by participants, as is the
case with notes held for the account of customers registered in "street name."
However, those payments will be the responsibility of the participants and not
of DTC, the trustee, the paying agent or us.

We will issue certificated notes in exchange for a global note with the
same terms in authorized denominations only if:

- DTC notifies us that it is unwilling or unable to continue as depositary
and we have not appointed a successor depositary within 90 days; or

- DTC requests an exchange and an event of default has occurred and is
continuing. [Section 312]

Certificated Notes

If we issue certificated notes, they will be registered in the name of the
holder of the note. The notes may be transferred or exchanged, pursuant to
administrative procedures in the indenture, without the payment of any service
charge (other than any tax or other governmental charge) by contacting the
trustee. [Section 305]

Principal of, interest and any premium on certificated notes will be paid
at designated places. Payment may be made by check mailed (or at our option, by
wire transfer) to the persons in whose names the notes are registered on the
days specified in the indenture. [Section 1001]

About DTC

DTC has provided us the following information:

DTC is a limited-purpose trust company organized under the New York
Banking Law, a "banking organization" within the meaning of the New York
Banking law, a member of the United States Federal Reserve System, a
"clearing corporation" within the meaning of the New York

45
<PAGE> 46

Uniform Commercial Code and a "clearing agency" registered under the
provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds
securities that its participants deposit with DTC. DTC also records the
settlement among participants of securities transactions, such as transfers
and pledges, in deposited securities through computerized records for
participants' accounts. This eliminates the need to exchange certificates.
Participants include securities brokers and dealers, banks, trust
companies, clearing corporations and certain other organizations.

DTC's book-entry system is also used by other organizations such as
securities brokers and dealers, banks and trust companies that work through
a participant. The rules that apply to DTC and it participants are on file
with the SEC.

DTC is owned by a number of its participants and by the New York Stock
Exchange, Inc., The American Stock Exchange, Inc. and the National
Association of Securities Dealers, Inc.

SUBORDINATION

The payment of principal, premium, if any, and interest on the notes will
be subordinated to the prior payment in full of all of our Senior Indebtedness.
[Section 1301]

The holders of Senior Indebtedness will be able to receive payment in full
of all amounts due in respect of Senior Indebtedness, before the holders of
notes will be able to receive any payment with respect to the notes, other than
payments in the form of Permitted Junior Securities, and payments made pursuant
to the terms described under the subheading "Consolidation, Merger and Sale of
Assets," if there is a distribution to our creditors:

- in our liquidation or dissolution;

- in a bankruptcy, reorganization, insolvency, receivership or similar
proceeding relating to us, our creditors or our property;

- in an assignment for the benefit of our creditors; or

- in any marshalling of our assets and liabilities. [Section 1302]

We also may not make any payment in respect of the notes, other than
payments of Permitted Junior Securities, if:

- a Payment Event of Default on Specified Senior Indebtedness occurs and is
continuing beyond any applicable grace period; or

- any other default occurs and is continuing on Specified Senior
Indebtedness that permits holders of the Specified Senior Indebtedness to
accelerate its maturity, and we receive or the trustee receives a notice
of such default (a "Payment Blockage Notice") from the holders of any
Specified Senior Indebtedness.

We will resume making payments on the notes and any missed payments:

- in the case of a Payment Event of Default, upon the date that we cure or
obtain the waiver of such default; and

- in case of a Non-payment Event of Default, the earlier of the date that
we cure or obtain the waiver of such Non-payment Event of Default or 179
days after the date on which we receive or the trustee receives the
applicable Payment Blockage Notice, or the date on which the holders that
initiated the Payment Blockage Notice terminate the payment blockage
period, unless the maturity of any Specified Senior Indebtedness has been
accelerated.

No new Payment Blockage Notice may be delivered unless and until 360
consecutive days have elapsed since the effectiveness of the immediately prior
Payment Blockage Notice. No Non-payment

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<PAGE> 47

Event of Default that existed or was continuing on the date of delivery of any
Payment Blockage Notice to us or the trustee can be made the basis for a
subsequent Payment Blockage Notice. [Section 1303]

Any payments that we fail to make on the notes when due or within an
applicable grace period will constitute an Event of Default under the indenture
that entitles holders of the notes to accelerate the maturity of the notes.
[Sections 501 and 502]

If the trustee or any holder of a note receives any payment or property
prohibited by the subordination provisions of the indenture, the payment and
property must be paid over to us or the person making payments to our creditors.
[Sections 1302 and 1303]

As a result of the subordination provisions described above, in the event
of our bankruptcy, liquidation or reorganization, holders of the notes may
recover less ratably than our creditors that are holders of Senior Indebtedness.
See "Risk Factors."

The subordination provisions described above will not apply to the notes
upon a legal or covenant defeasance described under the subheading "Legal
Defeasance and Covenant Defeasance."

CERTAIN COVENANTS

Restricted Payments

We will not, and will not permit any of our Restricted Subsidiaries to,
directly or indirectly:

- declare or pay any dividend or make any other payment or distribution on
account of our or any of our Restricted Subsidiaries' capital stock
(other than dividends or distributions payable to us or payable solely in
shares of our or their capital stock);

- purchase, redeem or retire any of our capital stock, or any capital stock
of a non-wholly owned Restricted Subsidiary, or any warrants, rights or
options to purchase or acquire any shares of such capital stock; or

- make any other payment or distribution in respect of our capital stock
(all such payments and other actions set forth in the three clauses above
being collectively referred to as "Restricted Payments"),

if, at the time of and after giving effect to such Restricted Payment:

- an Event of Default would have occurred; or

- such Restricted Payment, together with the aggregate amount of all other
Restricted Payments made by us and our Restricted Subsidiaries after the
date of the Indenture, would exceed the sum of:

(1) 50% of our Consolidated Net Income subsequent to June 30, 1999, with
100% reduction for a loss; plus

(2) the cumulative net proceeds received by us from the issuance and sale
after the date of the indenture of our capital stock, including in
such net proceeds the face amount of any indebtedness that has been
converted into our common stock after the date of the indenture.

So long as no Event of Default has occurred and is continuing, the
preceding provisions will not prohibit:

- Restricted Payments in an aggregate amount not to exceed $10 million;

- the payment of regular periodic dividends on shares of our series A
preferred stock or other series of our preferred stock; and

- the repurchase, redemption or other acquisition or retirement of any
shares of any class of our or any of our Restricted Subsidiaries' capital
stock in exchange for, or out of the aggregate net cash proceeds of a
substantially concurrent issuance and sale (other than to a Restricted
Subsidiary) of shares of our common stock.

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All such payments and other actions set forth in the three clauses above
being collectively referred to as "Permitted Restricted Payments." Permitted
Restricted Payments shall not reduce the amount that would otherwise be
available for Restricted Payments, except in the case of dividends declared or
paid on shares of our preferred stock (other than the series A preferred stock)
which dividends will reduce the amount available under clauses (1) and (2)
above. The amount of any Restricted Payments payable in property will be the
fair market value of such property as determined by our board of directors.
[Section 1006]

Incurrence of Indebtedness

We will not, and will not permit any of our Restricted Subsidiaries to,
create, incur, assume, guarantee or become liable ("incur"), with respect to any
Indebtedness for Money Borrowed (including Acquired Indebtedness but excluding
Permitted Indebtedness), if, immediately after we incur such debt (including
giving effect to the retirement of any existing Indebtedness for Money Borrowed
from the proceeds of such additional Indebtedness for Money Borrowed):

- the ratio of:

(1) the aggregate amount of our and our Restricted Subsidiaries'
outstanding Indebtedness for Money Borrowed as of the end of our
immediately preceding fiscal quarter, determined on a consolidated
basis under GAAP, to

(2) the Consolidated EBITDA for our immediately preceding four fiscal
quarters,

would exceed 10.0 to 1.0; or

- the ratio of:

(1) Consolidated EBITDA for our immediately preceding four fiscal
quarters, to

(2) Consolidated Interest Expense for our immediately preceding four
fiscal quarters,

would be less than 1.1 to 1.0.

We will also not permit any Restricted Subsidiary to incur any Indebtedness
for Money Borrowed, except to us or another Restricted Subsidiary, that is
expressly subordinate in right of payment to any other Indebtedness for Money
Borrowed of such Restricted Subsidiary. [Section 1007]

Liens

We will not, and will not permit any of our Restricted Subsidiaries to,
directly or indirectly, create, incur, assume or suffer to exist any Lien on any
asset now owned or hereafter acquired of any kind to secure any Pari Passu
Indebtedness or Subordinated Indebtedness, unless,

- the Lien is a Permitted Lien; or

- prior to, or at the same time that we incur a Lien, we directly secure
the notes equally and ratably, provided that:

(1) if such secured indebtedness is Pari Passu Indebtedness, the Lien
securing such Pari Passu Indebtedness is subordinate to, or pari passu
with, the Lien securing the notes; and

(2) if such secured indebtedness is Subordinate Indebtedness, the Lien
securing such Subordinated Indebtedness is subordinate to the Lien
securing the notes at least to the same extent as such Subordinated
Indebtedness is subordinated to the notes.

This covenant does not apply to any Lien securing Acquired Indebtedness,
provided that any such Lien extends only to the properties or assets that were
subject to such Lien prior to the acquisition by us or such Restricted
Subsidiary and we did not create, incur or assume any such Lien in contemplation
of such transaction. [Section 1008]

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Ranking of Future Indebtedness

We will not incur or permit to remain outstanding any Indebtedness for
Money Borrowed, including Acquired Indebtedness and Permitted Indebtedness,
which is expressly subordinate to any Senior Indebtedness, other than
Subordinated Indebtedness or Pari Passu Indebtedness. The incurrence of any
unsecured Senior Indebtedness is not, because of its unsecured status, deemed to
be subordinate in right of payment to any secured Senior Indebtedness. [Section
1013]

Dividend and Other Payment Restrictions Affecting Subsidiaries

We will not, and will not permit any of our Restricted Subsidiaries to,
directly or indirectly, create or cause any encumbrance or restriction on the
ability of any Restricted Subsidiary to:

- pay dividends in cash or make any other distribution on its capital stock
to us or any other Restricted Subsidiary;

- pay any indebtedness owed to us or any other Restricted Subsidiary;

- make loans, advances or capital contributions to us or any other
Restricted Subsidiary; or

- transfer any of its properties to us or another Restricted Subsidiary.

However, the preceding restrictions will not apply to encumbrances or
restrictions existing under or by reason of:

- an agreement governing Acquired Indebtedness of any acquired Person that
becomes a Restricted Subsidiary, provided, than any restriction or
encumbrance under such agreement existed at the time of acquisition, was
not put in place in anticipation of such acquisition, and is not
applicable to any Person other than the Person or property of the Person
so acquired;

- customary provisions of any of our or our Restricted Subsidiaries' leases
or licenses relating to the property covered that we or a Restricted
Subsidiary entered into in the ordinary course of business;

- applicable law;

- the indenture, the Credit Facility or other indebtedness or other
agreements existing on the date of original issuance of the notes;

- an agreement entered into for the sale or disposition of the stock,
business or properties of a Restricted Subsidiary;

- purchase money obligations, but only to the extent such purchase money
obligations restrict or prohibit the transfer of the property so
acquired;

- customary non-assignment provisions in installment purchase contracts;

- the requirements of a lender or purchaser of any indebtedness of a
Restricted Subsidiary in connection with a financing of the acquisition
of property, including the purchase of asset portfolios and the
underwriting or origination of mortgage loans, by such Restricted
Subsidiary to the extent such restriction applies to the transfer to us
or any other Restricted Subsidiary of such property acquired after the
date of the indenture;

- an agreement that extends, refinances, renews or replaces any agreement
described in the foregoing clauses; and

- Liens containing customary limitations on the transfer of collateral
which are not prohibited as described in the "Liens" covenant and do not
restrict the ability of a Restricted Subsidiary to transfer any of its
property or assets to us or another Restricted Subsidiary. [Section 1014]

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Transactions with Affiliates

We will not, and will not permit any of our Restricted Subsidiaries to,
enter into any transaction or series of related transactions involving payments
in excess of $50,000, with any of our Affiliates, other than ourselves or a
Restricted Subsidiary, unless our board of directors:

- determines that the transaction is on terms that are no less favorable to
us or the relevant Restricted Subsidiary than would be available at such
time in a comparable transaction in arm's length dealings with an
unrelated person; and

- the board of directors adopts a resolution evidencing such determination.

The preceding paragraph will not apply to:

- Restricted Payments that are permitted by the provisions of the Indenture
described above under "Restricted Payments;"

- fees and compensation paid to, and indemnity provided on behalf of, our
and our Restricted Subsidiaries' officers, directors, employees or
consultants; or

- payments for goods and services purchased in the ordinary course of
business on an arm's length basis. [Section 1015]

Change of Control

Upon the occurrence of a Change of Control, we are obligated to make an
offer to purchase all of the outstanding notes for a purchase price equal to
101% of the principal amount of the notes plus accrued and unpaid interest, if
any, on the notes to the date the offer is consummated. We are required to
purchase all notes tendered and not withdrawn.

In order to effect the Change of Control offer, we must mail to each holder
of the notes a notice of the Change of Control offer no later than 30 days after
the Change of Control occurs. We must consummate the offer on a business day not
less than 30 days nor more than 60 days after the mailing of the notice of the
Change of Control. We are required to keep the offer open for at least 20
business days. The notice governs the terms of the offer and states the
procedures that holders of notes must follow to accept the offer.

We will not be required to make a Change of Control offer upon a Change of
Control if a third party makes a Change of Control offer that meets the
requirements of the indenture, and purchases all notes validly tendered and not
withdrawn under the Change of Control offer.

The definition of Change of Control includes a phrase relating to the sale,
lease, transfer, conveyance or other disposition of "all or substantially all"
of our and our Restricted Subsidiaries' assets taken as a whole. Although there
is a limited body of case law interpreting the phrase "substantially all," there
is no precise established definition of the phrase under applicable law.
Accordingly, the ability of a holder of notes to require us to repurchase their
notes as a result of a sale, lease, transfer, conveyance or other disposition of
less than all of our and our Restricted Subsidiaries' assets taken as a whole
may be uncertain.

We will comply with Rule 14e-1 under the Exchange Act and any other
securities laws and regulations, to the extent these laws or regulations are
applicable, in connection with the repurchase of the notes as a result of a
Change of Control. [Section 1016]

REPORTS

As long as we are a reporting company under the Securities Exchange Act of
1934, we will furnish holders of the notes with our annual reports containing
audited consolidated financial statements and our interim reports containing our
quarterly unaudited consolidated summary financial data. If we cease to be a
reporting company, we will furnish holders of the notes with our audited
consolidated financial statements and our quarterly unaudited consolidated
summary financial statements. [Section 704]

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EVENTS OF DEFAULT AND REMEDIES

Each of the following is an Event of Default:

- failure to pay any interest on the notes when due for 30 days, whether or
not prohibited by the subordination provisions of the indenture;

- failure to pay the principal of (or premium, if any, on) the notes when
due as provided in the indenture, whether or not prohibited by the
subordination provisions of the indenture;

- failure to comply with the covenants under "-- Certain
Covenants -- Change of Control;"

- failure to perform, or a breach of, any other covenant set forth in the
indenture for 30 days after receipt of written notice from the trustee or
holders of at lest 25% in aggregate principal amount of the outstanding
notes specifying the default and requiring that we remedy such default;

- failure to pay at Stated Maturity of our or any Restricted Subsidiaries'
Indebtedness for Money Borrowed having an outstanding principal amount
due at Stated Maturity greater than $2.5 million for a period of 30 days
beyond any applicable grace period;

- an event of default as defined in any mortgage, indenture or instrument
of ours or a Restricted Subsidiary that has resulted in acceleration of
Indebtedness for Money Borrowed which, together with the principal amount
of any other Indebtedness for Money Borrowed so accelerated, exceeds $2.5
million at any time, and we do not cure or obtain the waiver of such
default and such acceleration is not rescinded or annulled within 30 days
from the occurrence of such acceleration;

- certain events of insolvency, receivership or reorganization of us or any
Material Subsidiary; and

- failure by us or any Material Subsidiary to satisfy a final judgment for
the payment of money in excess of $2.5 million for a period of 30 days
without a stay of execution. [Section 501]

If an Event of Default arising from certain events of insolvency,
receivership or reorganization occurs and is continuing, all outstanding notes
will become due and payable immediately without further action or notice. If any
other Event of Default occurs and is continuing,

- the trustee or the holders of at least 25% in aggregate principal amount
of the then outstanding notes may declare all the notes to be due and
payable immediately; and

- the trustee, upon the request of the holders of not less than 25% in
aggregate principal amount of the then outstanding notes, shall declare
all of the notes to be due and payable. [Section 502]

After a declaration of acceleration under the indenture, but before the
trustee obtains a judgment for payment of the money due, the holders of a
majority in aggregate principal amount of the outstanding notes may rescind such
declaration by written notice to us and the trustee, if:

- we have paid or deposited with the trustee a sum sufficient to pay:

(1) all sums paid or advanced by the trustee under the indenture and the
reasonable compensation, expenses, disbursements and advances of the
trustee, its agents and counsel;

(2) all overdue interest on the notes;

(3) the principal of any notes which have become due otherwise than by
such declaration of acceleration and interest at the rate borne by the
notes; and

(4) to the extent that payment of such interest is lawful, interest upon
overdue interest and principal at the rate borne by the notes (without
duplication);

- the rescission would not conflict with any judgment of a court of
competent jurisdiction; and

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<PAGE> 52

- we have cured or obtained the waiver of all Events of Default, other than
the nonpayment of principal of (or premium, if any, on) or interest on
the notes that has become due solely by such declaration of acceleration.
[Section 502]

A Holder of a note may institute proceedings for the enforcement of the
payment of the principal, premium, if any, and interest on such note on or after
the respective due dates expressed in such note. No Holder of any note will have
any right to institute any other proceedings with respect to the indenture,
unless:

- such holder has notified the trustee of a continuing Event of Default;

- the holders of at least 25% in aggregate principal amount of the
outstanding notes have made written request and offered reasonable
indemnity to the trustee to institute such proceedings as trustee under
the indenture;

- the trustee has not received directions inconsistent with such written
request by holders of a majority in aggregate principal amount of the
outstanding notes; and

- the trustee has failed to institute such proceedings within 60 days of
receipt of such notice. [Section 507 and 508]

If a default or Event of Default occurs and is continuing and is known to
the trustee, the trustee shall mail to each holder of notes notice of the
default or Event of Default within 90 days after the occurrence of such default
or Event of Default. The trustee may withhold from holders of the notes notice
of any continuing Event of Default, except an Event of Default relating to the
payment of principal (premium, if any) or interest, if it determines in good
faith that withholding notice is in their interest. [Section 602]

The holders of a majority in aggregate principal amount of the notes then
outstanding may on behalf of the holders of all of the notes waive any existing
Event of Default and its consequences, except a continuing Event of Default in
the payment of principal of (or premium, if any, on) or interest on the notes or
of a provision of the indenture that cannot be modified or amended without the
consent of the holder of each note affected as described below under the
subheading "Modification of Indenture; Waiver of Covenants." [Section 513]

We are required to deliver to the trustee annual and quarterly statements
regarding compliance with the indenture. Upon becoming aware of any default or
Event of Default, we are required to deliver to the trustee a statement
specifying such default or Event of Default. [Section 1011]

REDEMPTION AT OPTION OF THE COMPANY

We may redeem the notes, in whole or part, at 100% of their principal
amount plus accrued interest, on or after March 15, 2001 by giving not less than
30 nor more than 60 days' notice to the holders. If we elect to redeem less than
all of the notes, the trustee will select which notes, or portions of notes not
to be less than $1,000, to redeem. On the redemption date, interest will cease
to accrue on the notes or portions of notes called for redemption. [Article 11]

MODIFICATION OF INDENTURE; WAIVER OF COVENANTS

We generally may amend the indenture with the written consent of a majority
in principal amount of the outstanding notes. [Section 902] The holders of a
majority in principal amount of the outstanding notes may also waive our
compliance with certain covenants. [Section 1012] We must, however, obtain the
consent of each holder of notes affected by an amendment or waiver which does
any of the following:

- changes the maturity date of the principal of, or the due date of any
installment of interest on, any note;

- reduces the principal of, or the rate of interest on, any note;

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<PAGE> 53

- changes the place of payment or the currency in which any portion of the
principal of (or premium, if any, on), or interest on, any note is
payable;

- impairs the right to institute suit for enforcement of any such payment;

- reduces the percentage of holders of the outstanding notes necessary to
modify the indenture;

- modifies the foregoing requirements or reduces the percentage of
outstanding notes necessary to waive any past default or certain
covenants; or

- reduces the relative ranking of the notes. [Section 902]

CONSOLIDATION, MERGER AND SALE OF ASSETS

The indenture generally permits a consolidation, merger, or sale of all or
substantially all of our assets to another entity, subject to our obligation to
offer to repurchase the notes in the case of a transaction that is a Change of
Control as long as it does not cause a default or an Event of Default. If this
happens, the remaining or acquiring entity:

- if other than us, must be formed in a U.S. jurisdiction and must assume
our obligations under the indenture; and

- must be able to incur $1.00 of Indebtedness for Money Borrowed in
compliance with the incurrence of indebtedness covenant in the indenture
immediately after the merger. [Section 801]

LEGAL DEFEASANCE AND COVENANT DEFEASANCE

Legal Defeasance

As long as we take steps to ensure that you will receive all of your
payments under the notes and are able to transfer the notes, we can elect to
legally release ourselves from any obligations on the notes (called "legal
defeasance") other than:

- the rights of holders of outstanding notes to receive payment in respect
of the principal of (and premium, if any) and interest on such notes when
such payments are due;

- our obligation to replace any temporary notes, register the transfer or
exchange of any notes, replace mutilated, destroyed, lost or stolen notes
and maintain an office or agency for payments in respect of the notes;

- the rights, powers, trusts, duties and immunities of the trustee; and

- the legal defeasance provisions of the indenture. [Section 1202]

To accomplish legal defeasance, the following must occur:

- We must irrevocably deposit in trust for the benefit of all holders of
notes money and/or U.S. government or U.S. government agency notes or
bonds that will generate enough cash to make interest, principal and any
other payments on the notes on their various due dates.

- There must be a change in current U.S. federal tax law or an IRS ruling
that lets us make that deposit without causing you to be taxed on the
notes any differently than if we did not make the deposit and just repaid
the notes ourselves. (Under current U.S. federal tax law, the deposit and
our legal release from the securities would be treated as though we took
back your notes and gave you your share of the cash and notes or bonds
deposited in trust. In that event, you could recognize gain or loss on
the notes you give back to us.)

- We must deliver to the trustee a legal opinion of our counsel confirming
the tax law change described above and that all of the conditions to
legal defeasance in the indenture have been fulfilled.

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<PAGE> 54

We will not be able to achieve legal defeasance if there is a continuing
Event of Default under the indenture or if doing so would violate any other
material agreements to which we are a party. If we ever did accomplish legal
defeasance, as described above, you would have to rely solely on the trust
deposit for repayment on the notes. You could not look to us for repayment in
the unlikely event of any shortfall. [Section 1204]

Covenant Defeasance

Under current U.S. federal tax law, we can make the same type of deposit
described above and be released from certain covenants relating to the notes.
The release from these covenants is called "covenant defeasance." In that event,
you would lose the protection of these covenants but would gain the protection
of having money and securities set aside in trust to repay the notes. [Section
1203] In order to achieve covenant defeasance, we must do the following:

- deposit in trust for the benefit of all holders of the notes money and/or
U.S. government or U.S. government agency notes or bonds that will
generate enough cash to make interest, principal and any other payments
on the notes on their various due dates.

- deliver to the trustee a legal opinion of our counsel confirming that
under current U.S. federal tax law we may make that deposit without
causing you to be taxed on the notes any differently than if we did not
make the deposit and just repaid the notes ourselves. The opinion must
also state that all of the conditions to covenant defeasance in the
indenture have been fulfilled.

We will not be able to achieve covenant defeasance if there is a continuing
Event of Default under the indenture or if doing so would violate any other
material agreements to which we are a party. The indenture describes the
covenants that we may fail to comply with without causing an Event of Default if
we accomplish covenant defeasance. [Section 1204]

If we elect to make a deposit resulting in covenant defeasance, the amount
of money and/or U.S. government obligations deposited in trust should be
sufficient to pay amounts due on the notes at the time of their maturity.
However, if the maturity of the notes is accelerated due to the occurrence of an
Event of Default, the amount in trust may not be sufficient to pay all amounts
due on the notes. We will remain liable for the shortfall as described in the
indenture. [Article 12]

SATISFACTION AND DISCHARGE OF THE INDENTURE

We will have no further obligations under the indenture as to all
outstanding notes, other than surviving rights of registration of transfers of
the notes, when:

- all notes have been delivered to the trustee for cancellation; or all
notes have become due and payable or, within one year, will become due
and payable or be redeemed and we have deposited with the trustee funds
sufficient to pay interest, principal and any other payments on all
outstanding notes on their various due dates;

- we have paid all other sums then due and payable under the indenture by
us; and

- we have delivered to the trustee an officers' certificate and an opinion
of counsel, which, taken together, state that we have complied with all
conditions precedent under the indenture relating to the satisfaction and
discharge of the indenture. [Sections 401 and 402]

GOVERNING LAW

Legal interpretations of the indenture and notes will be made using the
laws of the State of New York. [Section 113]

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CONCERNING THE TRUSTEE

American Stock Transfer & Trust Company will act as trustee under the
indenture. The indenture provides for indemnification of the trustee by us under
certain circumstances. [Section 607]

The indenture limits the rights of the trustee to obtain payments of claims
in certain cases if it becomes our creditor. While the trustee is permitted to
engage in other transactions, if the trustee acquires any conflicting interests
governed by the Trust Indenture Act of 1939, the trustee must either eliminate
such conflict or resign. [Section 613 and 614]

The trustee is the transfer agent and registrar for our common stock and
series A preferred stock. Also, the trustee is the trustee under our 2001
Indenture and 2002 Indenture.

CERTAIN DEFINITIONS

Set forth below are certain defined terms used in the indenture. Reference
is made to the indenture for a full disclosure of all such terms, as well as any
other capitalized terms used herein for which no definition is provided.
(Section 101)

"Acquired Indebtedness" means Indebtedness for Money Borrowed of a Person
existing at the time such Person becomes a Restricted Subsidiary or assumed in
connection with the acquisition by us or a Restricted Subsidiary of assets from
such Person, and not incurred in connection with, or in anticipation of, such
Person becoming a Restricted Subsidiary or such acquisition. Acquired
Indebtedness shall be deemed to be incurred on the date of the related
acquisition of assets from any Person or the date the acquired Person becomes a
Restricted Subsidiary.

"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For the purposes of this definition,
"control", when used with respect to any specified Person, means the power to
direct the management and policies of such Person, directly or, indirectly,
whether through the ownership of voting securities, by contract or otherwise;
and the terms "controlling" and "controlled" have meanings correlative to the
foregoing.

"Average Life" means, with respect to any Indebtedness for Money Borrowed,
as at any date of determination, the quotient obtained by dividing:

- the sum of the products of:

(1) the number of years (and any portion thereof) from the date of
determination to the date or dates of each successive scheduled
principal payment (including, without limitation, any sinking fund or
mandatory redemption payment requirements) of such Indebtedness for
Money Borrowed multiplied by;

(2) the amount of each such principal payment; by

- the sum of all such principal payments.

"Capitalized Lease Obligation" means, as to any Person, the obligations of
such Person to pay rent or other amounts under the lease of (or other agreement
conveying the right to use) real or personal property which obligations are
required to be classified and accounted for as capital lease obligations on a
balance sheet of such Person under GAAP and, for purposes of the indenture, the
amount of such obligations at any date shall be the capital amount thereof at
such date, determined in accordance with GAAP.

"Change of Control" means the occurrence of any of the following:

- the sale, lease, transfer, conveyance or other disposition (other than by
way of merger or consolidation), in one or a series of related
transactions, of all or substantially all of our and our Restricted
Subsidiaries' assets taken as a whole to any "person" (as such term is
used in Section 13(d)(3) of the Securities Exchange Act of 1934);

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- the adoption of a plan relating to our liquidation or dissolution;

- the consummation of any transaction (including, without limitation, any
purchase, sale, acquisition, disposition, merger or consolidation) the
result of which is that any "person" (as defined above) becomes the
"beneficial owner" (as such term is described in Rule 13d-3 and Rule
13d-5 under the Securities Exchange Act of 1934), directly or indirectly,
of more than 50% of the aggregate voting power of all classes of our
Voting Stock, provided that the sale of our Voting Stock, or warrants,
options or rights to acquire our Voting Stock to an underwriter in
connection with a firm commitment underwriting shall not constitute a
Change of Control; or

- the first day on which a majority of the members of our board of
directors are not Continuing Directors.

"Consolidated EBITDA" means, for any period, determined in accordance with
GAAP on a consolidated basis for us and our Restricted Subsidiaries, the sum of
Consolidated Net Income, plus depreciation, depletion, amortization and other
non-cash charges, income tax expense, and Consolidated Interest Expense, for
such period, each as deducted in determining such Consolidated Net Income.

"Consolidated Interest Expense" means, for any period, the interest expense
for such period, which is required to be shown as such on both our and our
Restricted Subsidiaries' financial statements, on a consolidated basis, prepared
in accordance with GAAP.

"Consolidated Net Income" means, for any period, the amount of our and our
Restricted Subsidiaries' consolidated net income (loss) for such period,
determined in accordance with GAAP; provided, however, that there shall be
included in Consolidated Net Income any net extraordinary gains or losses for
such period (less all fees and expenses related thereto); and, provided,
further, that there shall not be included in Consolidated Net Income:

- any net income (loss) of a Restricted Subsidiary for any portion of such
period during which it was not a Consolidated Subsidiary;

- any net income (loss) of businesses, properties or assets acquired or
disposed of (by way of merger, consolidation, purchase, sale or
otherwise) by us or any Restricted Subsidiary for any portion of such
period prior to the acquisition thereof or subsequent to the disposition
thereof; or

- any net income for such period resulting from transfers of assets
received by us or any Restricted Subsidiary from an Unrestricted
Subsidiary.

"Consolidated Subsidiary" means a Restricted Subsidiary the financial
statements of which are consolidated with our financial statements.

"Continuing Directors" means, as of any date of determination, any member
of our board of directors who:

- was a member of our board of directors on the date of the indenture; or

- was nominated for election or elected to our board of directors with the
approval of a majority of the Continuing Directors who were members of
our board at the time of their nomination or election.

"Credit Facility" means that certain Amended and Restated Credit Agreement,
dated as of October 31, 1996, among us, Callon Petroleum Operating Company,
Callon Offshore Production, Inc., the several banks and other financial
institutions from time to time parties thereto (the "Banks"), and The Chase
Manhattan Bank, as agent for the Banks, as the same may be amended, modified,
supplemented, extended, restated, replaced, renewed or refinanced from time to
time.

"Event of Default" has the meaning specified under "Events of Default and
Remedies."

"GAAP" means United States generally accepted accounting principles set
forth in the opinions and pronouncements of the Accounting Principles board of
the American Institute of Certified Public
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<PAGE> 57

Accountants and statements' and pronouncements of the Financial Accounting
Standards Board in effect on the date of the indenture.

"Indebtedness for Money Borrowed" means any of the following of our or any
Restricted Subsidiary's obligations:

- any obligation, contingent or otherwise, for borrowed money or for the
deferred purchase price of property, assets, securities or services
(including, without limitation, any interest accruing subsequent to an
event of default);

- all obligations (including the notes) evidenced by bonds, notes,
debentures or other similar instruments;

- all indebtedness created or arising under any conditional sale or other
title retention agreement with respect to property acquired (even though
the rights and remedies of the seller or lender under such agreement in
the event of default are limited to repossession or sale of such
property), except any such obligation that constitutes a trade payable
and an accrued liability arising in the ordinary course of business, if
and to the extent any of the foregoing indebtedness would appear as a
liability upon a balance sheet prepared in accordance with GAAP;

- all Capitalized Lease Obligations;

- our liabilities actually due and payable under bankers acceptances and
letters of credit;

- all indebtedness of the type referred to in the preceding five clauses
secured by (or for which the holder of such indebtedness has an existing
right, contingent or otherwise, to be secured by) any Lien upon or
security interest in our or any Restricted Subsidiary's property
(including, without limitation, accounts and contract rights), even
though neither we nor any Restricted Subsidiary has assumed or become
liable for the payment of such indebtedness; and

- any guarantee or endorsement (other than for collection or deposit in the
ordinary course of business) or discount with recourse of, or other
agreement, contingent or otherwise, to purchase, repurchase, or otherwise
acquire, to supply, or advance funds or become liable with respect to,
any indebtedness or any obligation of the type referred to in any of the
preceding six clauses, regardless of whether such obligation would appear
on a balance sheet.

Provided, however, that Indebtedness for Money Borrowed shall not include:

- Production Payments and Reserve Sales;

- any liability for gas balancing incurred in the ordinary course of
business;

- our or a Restricted Subsidiary's accounts payable or other obligations in
the ordinary course of business in connection with the obtaining of goods
or services; and

- any liability under any and all:

(1) employment or consulting agreements or employee benefit plans or
arrangements; and

(2) futures contracts, forward contracts, swap, cap or collar contracts,
option contracts, or other similar derivative agreements.

"Lien" means any mortgage, charge, pledge, lien (statutory or other),
security interest, hypothecation, assignment for security, claim, or preference
or priority or other encumbrance or similar agreement or preferential
arrangement of any kind or nature whatsoever (including, without limitation, any
agreement to give or grant a Lien or any lease, conditional sale or other title
retention agreement having substantially the same economic effect as any of the
foregoing) upon or with respect to any property of any kind. A Person shall be
deemed to own subject to a Lien any property which such Person has acquired or
holds subject to the interest of a vendor or lessor under any conditional sale
agreement, capital lease or other title retention agreement.
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"Material Subsidiary" means any Restricted Subsidiary whose assets or
revenues comprise at least five percent (5%) of our and our Restricted
Subsidiaries' assets or revenues on a consolidated basis as of the end of, or
for, our most recently completed fiscal quarter, as determined from time to
time.

"Non-payment Event of Default" means any event (other than a Payment Event
of Default), the occurrence of which (with or without notice or the passage of
time) entitles one or more Persons to accelerate the maturity of any Specified
Senior Indebtedness.

"Pari Passu Indebtedness" means any of our Indebtedness for Money Borrowed
that is pari passu in right of payment to the notes.

"Payment Event of Default" means any default in the payment or required
prepayment of principal of (or premium, if any) or interest on any Specified
Senior Indebtedness when due (whether at final maturity, upon scheduled
installment; upon acceleration or otherwise).

"Permitted Indebtedness" means any of the following:

- Indebtedness for Money Borrowed outstanding on the date of the indenture
(and not repaid or defeased with the proceeds of the offering of the
notes);

- Our Indebtedness for Money Borrowed to a Restricted Subsidiary and
Indebtedness for Money Borrowed of a Restricted Subsidiary to us or a
Restricted Subsidiary; provided, however, that upon any event which
results in any such Restricted Subsidiary ceasing to be a Restricted
Subsidiary or any subsequent transfer of any such Indebtedness for Money
Borrowed (except to us or a Restricted Subsidiary), such Indebtedness for
Money Borrowed shall be deemed, in each case, to be incurred and shall be
treated as an incurrence for purposes of the "Incurrence of Indebtedness"
covenant at the time the Restricted Subsidiary in question ceased to be a
Restricted Subsidiary;

- any guarantee of Senior Indebtedness incurred in compliance with the
"Incurrence of Indebtedness" covenant, by us or a Restricted Subsidiary;
and

- any renewals, substitutions, refinancings or replacements (each, for
purposes of this clause, a "refinancing") by us or a Restricted
Subsidiary of any Indebtedness for Money Borrowed outstanding on the date
of the indenture (and not repaid or defeased with the proceeds of the
offering of the notes), including any successive refinancings by us or
such Restricted Subsidiary, so long as:

(1) any such new Indebtedness for Money Borrowed shall be in a principal
amount that does not exceed the principal amount (or, if such
Indebtedness for Money Borrowed being refinanced provides for an
amount less than the principal amount thereof to be due and payable
upon a declaration of acceleration thereof, such lesser amount as of
the date of determination) so refinanced plus the amount of any
premium required to be paid in connection with such refinancing
pursuant to the terms of the Indebtedness for Money Borrowed
refinanced or the amount of any premium reasonably determined by us or
such Restricted Subsidiary as necessary to accomplish such
refinancing, plus the amount of our or such Restricted Subsidiary's
expenses incurred in connection with such refinancing; and

(2) in the case of any refinancing of our Indebtedness for Money Borrowed
that is not Senior Indebtedness, such new Indebtedness for Money
Borrowed is either pari passu with the notes or subordinated to the
notes at least to the same extent as the Indebtedness being
refinanced; and

(3) such new Indebtedness for Money Borrowed has an Average Life equal to
or longer than the Average Life of the Indebtedness for Money Borrowed
being refinanced and a final Stated Maturity equal to or later than
the final Stated Maturity of the Indebtedness for Money Borrowed being
refinanced.

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"Permitted Junior Securities" means any of our or any successor obligor's
equity securities or subordinated debt securities with respect to the Senior
Indebtedness provided for by a plan of reorganization or readjustment that, in
the case of any such subordinated debt securities, are subordinated in right of
payment to all Senior Indebtedness that may at the time be outstanding to
substantially the same degree as, or to a greater extent than, the notes are so
subordinated as provided in the indenture.

"Permitted Liens" means any of the following types of Liens:

- Liens existing as of the date the notes are first issued (except to the
extent such Liens secure any Pari Passu Indebtedness or Subordinated
Indebtedness that is repaid or defeased with proceeds of the offering of
the notes), and any renewal, extension or refinancing of any such Lien
provided that thereafter such Lien extends only to the properties that
were subject to such Lien prior to the renewal, extension or refinancing
thereof;

- Liens securing the notes; and

- Liens in favor of us.

"Person" means any individual, corporation, partnership, joint venture,
association, joint stock company, limited liability company, trust,
unincorporated organization or government or any agency or political subdivision
thereof.

"Production Payments and Reserve Sales" means the grant or transfer to any
Person of a royalty, overriding royalty, net profits interest, production
payment (whether volumetric or dollar denominated), master limited partnership
interest or other interest in oil and gas properties, which reserves the right
to receive all or a portion of the production or the proceeds from the sale of
production attributable to such properties where the holder of such interest has
recourse solely to such production or proceeds of production, subject to the
obligation of the grantor or transferor to operate and maintain, or cause the
subject interests to be operated and maintained, in a reasonably prudent manner
or other customary standard and/or subject to the obligation of the grantor or
transferor to indemnify for environmental matters.

"Restricted Subsidiary" means any Subsidiary, whether existing on or after
the date of the indenture, unless such Subsidiary is an Unrestricted Subsidiary
or is designated as an Unrestricted Subsidiary pursuant to the terms of the
indenture;

"Senior Indebtedness" means the principal amount of, and interest on and
all other amounts due on or in connection with:

- any of our Indebtedness for Money Borrowed, whether now outstanding or
hereafter created, incurred, assumed or guaranteed, unless in the
instrument creating or evidencing such Indebtedness for Money Borrowed or
pursuant to which such Indebtedness for Money Borrowed is outstanding it
is provided that such indebtedness is subordinate in right of payment or
in rights upon liquidation to any other of our Indebtedness for Money
Borrowed; and

- all renewals, extensions and refundings of any such indebtedness.

"Specified Senior Indebtedness" means:

- all of our Senior Indebtedness in respect of the Credit Facility and any
renewals, amendments, extensions, supplements, modifications, deferrals,
refinancings, or replacements (each, for purposes of this definition, a
"refinancing") thereof by us, including any successive refinancings
thereof by us; and

- any other Senior Indebtedness and any refinancings thereof by us having a
principal amount of at least $5 million as of the date of determination
and provided that the agreements, indentures or other instruments
evidencing such Senior Indebtedness or pursuant to which such Senior

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Indebtedness was issued specifically designates such Senior Indebtedness
as "Specified Senior Indebtedness" for purposes of the indenture.

For purposes of this definition, a refinancing of any Specified Senior
Indebtedness shall be treated as Specified Senior Indebtedness only if the
Senior Indebtedness issued in such refinancing ranks or would rank pari passu
with the Specified Senior Indebtedness refinanced and only if the Senior
Indebtedness issued in such refinancing is permitted by the covenant described
under "Certain Covenants -- Incurrence of Indebtedness."

"Stated Maturity" with respect to any note or any installment of principal
thereof or interest thereon means the date established by the indenture as the
fixed date on which the principal of such note or such installment of principal
or interest is due and payable, and, when used with respect to any other
Indebtedness for Money Borrowed or any installment of interest thereon, means
the date specified in the instrument evidencing or governing such Indebtedness
for Money Borrowed as the fixed date on which the principal of such Indebtedness
for Money Borrowed or such installment of interest is due and payable.

"Subordinated Indebtedness" means our Indebtedness for Money Borrowed which
is expressly subordinated in right of payment to the notes, including, without
limitation, the convertible debentures described under "Description of Capital
Stock -- Convertible Debentures."

"Subsidiary" means any corporation of which at the time of determination we
or one or more Subsidiaries own or control directly or indirectly more than 50%
of the Voting Stock.

"2001 Indenture" means that certain indenture dated as of November 27, 1996
between Callon and American Stock Transfer & Trust Company, as trustee, as the
same may have been amended or supplemented from time to time prior to the date
hereof.

"2002 Indenture" means that certain indenture dated as of July 31, 1997
between Callon and American Stock Transfer & Trust Company, as trustee, as the
same may have been amended or supplemented from time to time prior to the date
hereof.

"Unrestricted Subsidiary" means:

- any Subsidiary that at the time of determination will be designated an
Unrestricted Subsidiary by the board of directors as provided below; and

- any Subsidiary of an Unrestricted Subsidiary.

The board of directors may designate any Subsidiary as an Unrestricted
Subsidiary so long as neither we nor any Restricted Subsidiary is directly or
indirectly liable pursuant to the terms of any Indebtedness for Money Borrowed
of such Subsidiary or have any assets or properties which are subject to any
Lien securing any Indebtedness for Money Borrowed of such Subsidiary. Any such
designation by the board of directors shall be evidenced to the trustee by
filing a board resolution with the trustee giving effect to such designation.
The board of directors may designate any Unrestricted Subsidiary as a Restricted
Subsidiary if, immediately after giving effect to such designation:

- no Event of Default shall have occurred and be continuing; and

- we could occur $l.00 of additional Indebtedness for Money Borrowed (other
than Permitted Indebtedness) under the "Incurrence of Indebtedness"
covenant.

"Voting Stock" means stock, interests, participations, rights in or other
equivalents in the equity interests (however designated) with respect to a
corporation having general voting power under ordinary circumstances to elect at
least a majority of the board of directors, managers or trustees of such
corporation, provided that, for the purposes hereof, stock which carries only
the right to vote conditionally on the happening of an event shall not be
considered Voting Stock whether or not such event shall have happened.

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DESCRIPTION OF BANK CREDIT FACILITY AND OTHER INDEBTEDNESS

BANK CREDIT FACILITY

Borrowings under our bank credit facility are secured by mortgages covering
substantially all of our producing oil and gas properties. Currently, the credit
facility provides for a $50 million borrowing base which is adjusted
periodically on the basis of a discounted present value of future net cash flows
attributable to our proved producing oil and gas reserves. Our borrowing base is
currently being evaluated by our bank and we expect our borrowing base to be
reduced in connection with the offering of the notes. Under our bank credit
facility, the interest rate is equal to the lender's prime rate plus 0.125% but
increases to prime plus 0.50% if we borrow more than 50% of our borrowing base.
At our option, we may fix the interest rate on all or a portion of the
outstanding principal balance at 1.125% above a defined "Eurodollar" rate for
periods up to six months which increases to 1.5% if we borrow more than 50% of
our borrowing base. The weighted average interest rate for the total debt
outstanding at December 31, 1998 and 1997 was 6.68% and 8.50%, respectively.
Under the credit facility, a quarterly commitment fee of 0.25% is assessed on
the unused portion of the borrowing base which increases to 0.375% if we borrow
more than 50% of our borrowing base. We may borrow, pay, reborrow and repay
under the credit facility until October 31, 2000, on which date we must repay in
full all amounts then outstanding.

Borrowings under the bank credit facility are guaranteed by our material
subsidiaries. The bank credit facility has several customary covenants
including, but not limited to, covenants that limit our ability to:

- repurchase capital stock;

- guaranty borrowings or borrow additional funds;

- prepay other indebtedness;

- merge;

- sell property;

- engage in transactions with our affiliates;

- hedge our production; and

- make acquisitions.

We are also required by the bank to maintain several financial ratios and
conditions so that the bank can monitor our financial stability.

OUTSTANDING NOTES

On November 27, 1996, we sold $24.2 million aggregate principal amount of
10% Senior Subordinated Notes due December 15, 2001. Payments of principal,
interest and premium, if any, under these notes are subordinate to all of our
existing and future senior indebtedness. These notes rank equally with the notes
offered in this prospectus. The 10% notes are not entitled to the benefit of any
mandatory sinking fund payments and are subject to redemption at anytime on or
after December 15, 1997, at our option, at par plus accrued and unpaid interest
to the date fixed for redemption.

On July 31, 1997, we sold $36 million aggregate principal amount of our
10.125% Series A Senior Subordinated Notes due September 15, 2002 through a
private placement transaction. On September 10, 1997, we commenced an offer to
exchange the notes for a like principal amount of 10.125% Series B Senior
Subordinated Notes due September 15, 2002. The form and terms of the series B
notes are identical in all material respects to the terms of the series A notes,
except the series A notes have certain transfer restrictions and provisions
relating to registration rights. Payments of principal, interest and premium, if
any, under the series A and series B notes are subordinate to all of our
existing and future senior indebtedness and rank equally with the notes offered
in this prospectus. The series A and series B notes are not entitled to the
benefit of any mandatory sinking fund payments and are subject to
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redemption at anytime on or after September 15, 2000, at our option, at par plus
accrued and unpaid interest to the date fixed for redemption.

Our outstanding notes contain covenants substantially similar to the notes.
However, several covenants contained in the indenture for the 10.125% notes are
more restrictive than covenants contained in the indenture for the 10% notes and
the notes offered in this document. If we violate these covenants we may trigger
cross-default and cross-acceleration provisions contained in the indentures for
the 10% notes and the notes. See "Description of the Notes -- Certain
Covenants."

DESCRIPTION OF CAPITAL STOCK

COMMON STOCK

We are authorized to issue up to 20,000,000 shares of common stock, $0.01
par value. As of March 31, 1999, 8,545,517 shares of common stock were issued
and outstanding.

Holders of common stock are entitled to one vote per share in the election
of directors and on all other matters submitted to a vote of stockholders.
Holders do not have the right to cumulate their votes in the election of
directors. Holders of common stock have no redemption or conversion rights and
no preemptive or other rights to subscribe for our securities. In the event of
our liquidation, dissolution or winding up, holders of common stock are entitled
to share equally and ratably in all of the assets remaining, if any, after
satisfaction of all our debts and liabilities, and of the preferential rights of
any series of preferred stock then outstanding. The outstanding shares of common
stock are validly issued, fully paid and nonassessable. Holders of common stock
are entitled to receive dividends when, as and if declared by the board of
directors out of funds legally available therefor. American Stock Transfer &
Trust Company is transfer agent and registrar for the common stock.

PREFERRED STOCK

We are authorized to issue 2,500,000 shares of preferred stock, $0.01 par
value per share. Our board of directors has the authority to divide the
preferred stock into one or more series and to fix and determine the relative
rights and preferences of the shares of each such series, including dividend
rates, terms of redemption, sinking funds, the amount payable in the event of
our voluntary liquidation, dissolution or winding up of our affairs, conversions
rights and voting powers. We have authorized the issuance of the Convertible
Exchangeable Preferred Stock, Series A, consisting of up to 1,380,000 shares of
preferred stock.

Series A Preferred Stock

In November 1995, we issued and sold 1,315,500 shares of series A preferred
stock.

Dividend Rights. Holders of the series A preferred stock are entitled to an
annual cash dividend of $2.125 per share, payable quarterly. If dividends are
not paid in full on all outstanding shares of the series A preferred stock and
any other security ranking on parity with the series A preferred stock,
dividends declared on the series A preferred stock and such other parity stock
are paid pro rata. Unless full cumulative dividends on all outstanding shares of
series A preferred stock have been paid, no dividends (other than in common
stock or other stock ranking junior to the series A preferred stock) may be
paid, or any other distributions made, on the common stock or on any other stock
of ours ranking junior to the series A preferred stock, nor may any common stock
or any other stock of ours ranking junior to or on a parity with the series A
preferred stock be redeemed, purchased or otherwise acquired for any
consideration by us (except by conversion into or exchange for stock of Callon
ranking junior to the series A preferred stock).

Conversion. The series A preferred stock is convertible at any time prior
to being called for redemption into common stock at a rate of approximately
2.273 shares of common stock for each share of series A preferred stock, subject
to adjustment for certain antidilutive events. From time to time, we may
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reduce the conversion price by any amount for a period of at least 20 days if
the board of directors determines that such reduction is in our best interests.
In the event of certain changes in control or fundamental changes, holders of
series A preferred stock have the right to convert all of their series A
preferred stock into common stock at a rate equal to the average of the last
reported sales prices of the common stock for the five business days ending on
the last business day preceding the date of the change in control or fundamental
change. We or our successor may elect to distribute cash to such holders in lieu
of common stock at an equal value.

Exchange. The series A preferred stock may be exchanged at our option for
convertible debentures beginning on January 15, 1998 at the rate of $25
principal amount of convertible debentures for each share of preferred stock,
provided that all accrued and unpaid dividends have been paid and certain other
conditions are met. See "Convertible Debentures" below.

Redemption. On or after December 31, 1998 we may from time to time redeem
the series A preferred stock at an initial redemption price of $26.488. On
December 31 of each year thereafter and until December 31, 2005, the redemption
price decreases. On December 31, 2005 and thereafter, the redemption price shall
remain at $25.

Voting Rights. The holders of series A preferred stock have no voting
rights, except as otherwise provided by law. However, if dividend payments are
in arrears in an amount equal to or exceeding six quarterly dividends, the
number of our directors will be increased by two and the holders of the series A
preferred stock (voting separately as a class) will be entitled to elect the
additional two directors until all dividends have been paid. In addition, we may
not create, issue or increase the authorized number of shares of any class or
series of stock ranking senior to the series A preferred stock or alter, change
or repeal any of the powers, rights or preferences of the holders of the series
A preferred stock as to adversely affect such powers, rights or preferences.

In a December 1998 private transaction, a preferred stockholder elected to
convert 59,689 shares of preferred stock into 136,867 shares of our common
stock. Subsequent to December 31, 1998, several other preferred stockholders,
through private transactions, converted 210,350 shares of preferred stock into
502,632 shares of our common stock under similar terms.

CONVERTIBLE DEBENTURES

At our option, the series A preferred stock may be converted into
convertible debentures. The convertible debentures, if issued, will be issued
under an indenture between Callon and Bank One, Columbus, NA, as trustee, a copy
of which is filed as an exhibit to our Form 10-K for fiscal year 1996.

General. The convertible debentures will be our unsecured, subordinated
obligations, limited in aggregate principal amount to the aggregate liquidation
preference of the series A preferred stock and will mature on December 31, 2010.
We must pay interest on the convertible debentures semiannually following the
issue thereof at the rate of 8.5% per annum. The convertible debentures are to
be issued in fully registered form, without coupons, in denominations of $25 or
any integral multiple thereof.

Conversion. The convertible debentures will be convertible at any time
after issue and prior to being called for redemption into common stock at the
conversion rate in effect on the series A preferred stock at the date of
exchange, subject to adjustment for certain antidilutive events. From time to
time we may reduce the conversion price in order that certain stock-related
distributions which may be made by us to our shareholders will not be taxable.
Each holder of a convertible debenture will be entitled to conversion rights
identical in substance to the rights applicable to holders of series A preferred
stock in the event of a change in control or fundamental change.

Subordination. Payment of principal of (and premium, if any) and interest
on the convertible debentures will be subordinated and junior in right of
payment to the prior payment in full of all senior indebtedness of Callon,
including the notes. During the continuation of any default in the payment of
principal, interest or premium on any senior indebtedness, no payment with
respect to the principal,

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interest or premium (if any) on the convertible debentures may be made until
such default on the senior indebtedness shall have been cured or waived or shall
have ceased to exist.

Redemption. On or after December 31, 1998, the convertible debentures may
be redeemed at our option at a redemption price (expressed as percentages of
principal amount) of 105.95%. On December 31 of each year thereafter and until
December 31, 2005, the redemption price decreases. On December 31, 2005 and
thereafter, the redemption price shall remain at 100.00%.

Events of Default. Upon an "event of default," the trustee or the holders
of at least 25% in aggregate principal amount of the outstanding convertible
debentures may accelerate the maturity of all convertible debentures, subject to
certain conditions. An event of default is defined in the indenture generally
as:

- failure to pay principal or premium, if any, on any convertible debenture
when due at maturity, upon redemption or otherwise;

- failure to pay an interest on any convertible debenture when due and
continuing for 30 days;

- breach of such indenture or convertible debentures by us;

- certain events in bankruptcy, insolvency or reorganization;

- default on indebtedness (other than non-recourse indebtedness) resulting
in more than $7,500,000 becoming due and payable prior to its maturity;
or

- a judgment or decree entered against us involving a liability of
$7,500,000 or more.

UNDERWRITING

We have entered into an underwriting agreement for the offering with the
underwriters named below. Subject to certain conditions, each underwriter has
severally agreed to purchase the principal amount of notes indicated in the
following table.

<TABLE>
<CAPTION>
PRINCIPAL AMOUNT
UNDERWRITERS OF NOTES
- ------------ ----------------
<S> <C>
A.G. Edwards & Sons, Inc.................................... $30,000,000
Morgan Keegan & Company, Inc................................ 10,000,000
-----------
Total............................................. $40,000,000
===========
</TABLE>

Notes sold by the underwriters to the public will initially be offered at
the initial public offering price set forth on the cover of this prospectus. Any
notes sold by the underwriters to securities dealers may be sold at a discount
from the initial public offering price of up to 1.75% of the principal amount of
the notes. Any such securities dealers may resell any notes purchased from the
underwriters to other brokers or dealers at a discount from the initial public
offering price up to 0.25% per note from the initial public offering price. If
all the notes are not sold at the initial offering price, the underwriters may
change the offering price and the other selling terms.

The notes are a new issue of securities with no established trading market.
The notes have been approved for listing on the New York Stock Exchange. We have
been advised by the underwriters that the underwriters intend to make a market
in the notes but are not obligated to do so and may discontinue market making at
any time without notice. No assurance can be given as to the liquidity of the
trading market for the notes.

In connection with the offering, the underwriters may purchase and sell
notes in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short
sales. Short sales involve the sale by the underwriters of a greater amount of
notes than they are required to purchase in the offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market price of the notes while the
offering is in progress.

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The underwriters also may impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount received by it because the underwriters have repurchased notes sold by
or for the account of such underwriter in stabilizing or short covering
transactions.

These activities by the underwriters may stabilize, maintain or otherwise
affect the market price of the notes. As a result, the price of the notes may be
higher than the price that otherwise might exist in the open market. If these
activities are commenced, they may be discontinued by the underwriters at any
time. These transactions may be effected in the over-the-counter market or
otherwise.

We have agreed to indemnify the several underwriters against various
liabilities, including liabilities under the Securities Act of 1933.

We estimate that the expenses of the offering, excluding underwriting
discounts and commissions, will be approximately $250,000.

VALIDITY OF THE NOTES

Our lawyers, Butler & Binion, L.L.P., Houston, Texas, will issue opinions
about the validity of the notes for us. Certain legal matters will be passed
upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The audited consolidated financial statements as of December 31, 1998, and
for the three years in the period ended December 31, 1998, included elsewhere in
this registration statement have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their report with respect
thereto, and are included herein in reliance upon the authority of said firm as
experts in accounting and auditing in giving said reports.

The information appearing in this prospectus regarding our quantities of
oil and gas and future net cash flows and the present values thereof from such
reserves is based on estimates of such reserves and present values prepared by
Huddleston & Co., Inc., an independent petroleum and geological engineering
firm.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other
information with the SEC. Our SEC filings are available to the public over the
Internet at the SEC's web site at http://www.sec.gov. You may also read and copy
any document we file at the SEC's public reference room at 450 Fifth Street,
N.W., Washington, D.C. 20549, and at the regional offices of the SEC located at
7 World Trade Center, Suite 1300, New York, New York 10048 and at 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661. You may obtain information
on the operation of the SEC's public reference room in Washington, D.C. by
calling the SEC at 1-800-SEC-0330. We also file such information with the New
York Stock Exchange. Such reports, proxy statements and other information may be
read and copied at 30 Broad Street, New York, New York 10005.

The SEC allows us to "incorporate by reference" the information we file
with them, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
an important part of this prospectus, and information that we file later with
the SEC will automatically update and supersede this information. We incorporate
by reference the documents listed below and any further filings made with the
SEC under Sections 13(a), 13(c), 14, or

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15(d) of the Securities Exchange Act of 1934 (the "Exchange Act") until we sell
all of the securities or we terminate this offering:

- Our Annual Report on Form 10-K for the year ended December 31, 1998;

- Our Quarterly Report on Form 10-Q for the quarter ended March 31, 1999;
and

- Our Current Reports on Form 8-K, filed on February 3, 1999 and March 3,
1999.

You may request a copy of these filings at no cost, by writing or
telephoning us at the following address:

H. Michael Tatum
200 North Canal Street
Natchez, MS 39120
1 (800) 451-1294

You should rely only on the information incorporated by reference or
provided in this prospectus or any prospectus supplement. We have not authorized
anyone else to provide you with different information. We are not making an
offer of these securities in any state where the offer is not permitted. You
should not assume that the information in this prospectus is accurate as of any
date other than the date on the front of those documents.

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GLOSSARY OF OIL AND GAS TERMS

TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS

- BBL -- One stock tank barrel, or 42 US gallons liquid volume, of crude
oil or other liquid hydrocarbons.

- BCF -- One billion cubic feet of natural gas.

- BCFE -- One billion cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

- MBBL -- One thousand Bbl.

- MCF -- One thousand cubic feet of natural gas.

- MCFE -- One thousand cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

- MMCF -- One million cubic feet of natural gas.

- MMCFE -- One million cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.

TERMS USED TO DESCRIBE OUR INTERESTS IN WELLS AND ACREAGE

- GROSS OIL AND GAS WELLS OR ACRES -- Our gross wells or gross acres
represents the total number of wells or acres in which we own a working
interest.

- NET OIL AND GAS WELLS OR ACRES -- Determined by multiplying "gross" oil
and natural gas wells or acres by the working interest that we own in
such wells or acres represented by the underlying properties.

TERMS USED TO ASSIGN A PRESENT VALUE TO OUR RESERVES

- STANDARDIZED MEASURE OF PROVED RESERVES -- The present value, discounted
at 10%, of the pre-tax future net cash flows attributable to estimated
net proved reserves. We calculate this amount by assuming that we will
sell the oil and gas production attributable to the proved reserves
estimated in our independent engineer's reserve report for the prices we
received for the production on the date of the report, unless we had a
contract to sell the production for a different price. We also assume
that the cost to produce the reserves will remain constant at the costs
prevailing on the date of the report. The assumed costs are subtracted
from the assumed revenues resulting in a stream of future net cash flows.
Estimated future income taxes using rates in effect on the date of the
report are deducted from the net cash flow stream. The after-tax cash
flows are discounted at 10% to result in the standardized measure of our
proved reserves. The standardized measure of our proved reserves is
disclosed in our financial statements at note 12.

- DISCOUNTED PRESENT VALUE -- The discounted present value of proved
reserves is identical to the standardized measure, except that estimated
future income taxes are not deducted in calculating future net cash
flows. We disclose the discounted present value without deducting
estimated income taxes to provide what we believe is a better basis for
comparison of our reserves to other producers who may have different tax
rates.

TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES

- PROVED RESERVES -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering
data, appear with reasonable certainty to be recoverable in the future
from known oil and natural gas reservoirs under existing economic and
operating conditions.

67
<PAGE> 68

The Securities and Exchange Commission definition of proved oil and gas
reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:

PROVED OIL AND GAS RESERVES. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.

(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.

(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.

(c) Estimates of proved reserves do not include the following: (1) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (2) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (3) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (4) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.

- PROVED DEVELOPED RESERVES -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.

- PROVED UNDEVELOPED RESERVES -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required.

TERMS WHICH DESCRIBE THE COST TO ACQUIRE OUR RESERVES

- RESERVE REPLACEMENT COSTS -- Our reserve replacement costs compare the
amount we spent to explore for oil and gas and to drill and complete
wells during a period, with the increases in reserves during the period.
This amount is calculated by dividing the net change in our evaluated oil
and property costs during a period by the change in proved reserves plus
production over the same period.

TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES

- RESERVE LIFE -- A measure of the productive life of an oil and gas
property or a group of oil and gas properties, expressed in years.
Reserve life equals the estimated net proved reserves attributable to a
property or group of properties divided by production from the property
or group of properties for the four fiscal quarters preceding the date as
of which the proved reserves were estimated.

TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF OUR OIL AND GAS PROPERTIES

- ROYALTY INTEREST -- A real property interest entitling the owner to
receive a specified portion of the gross proceeds of the sale of oil and
natural gas production or, if the conveyance creating the interest
provides, a specific portion of oil and natural gas produced, without any
deduction for the costs to explore for, develop or produce the oil and
natural gas. A royalty interest owner has no

68
<PAGE> 69

right to consent to or approve the operation and development of the
property, while the owners of the working interest have the exclusive
right to exploit the mineral on the land.

Working interest -- A real property interest entitling the owner to receive
a specified percentage of the proceeds of the sale of oil and natural gas
production or a percentage of the production, but requiring the owner of the
working interest to bear the cost to explore for, develop and produce such oil
and natural gas. A working interest owner who owns a portion of the working
interest may participate either as operator or by voting his percentage interest
to approve or disapprove the appointment of an operator and drilling and other
major activities in connection with the development and operation of a property.

TERMS USED TO DESCRIBE SEISMIC OPERATIONS

- Seismic data - Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in
exploration for new deposits and to manage or enhance production from
known reservoirs. To gather seismic data, an energy source is used to
send sound waves into the subsurface strata. These waves are reflected
back to the surface by underground formations, where they are detected by
geophones which digitize and record the reflected waves. Computers are
then used to process the raw data to develop an image of underground
formations.

- 2-D seismic data - 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad
area. 2-D seismic data is collected by a single line of energy sources
which reflect seismic waves to a single line of geophones. When
processed, 2-D seismic data produces an image of a single vertical plane
of sub-surface data.

- 3-D seismic - 3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey
produces a three dimensional image of the subsurface geology by
collecting seismic data along parallel lines and creating a cube of
information that can be divided into various planes, thus improving
visualization. Consequently, 3-D seismic data is a more reliable
indicator of potential oil and natural gas reservoirs in the area
evaluated.

69
<PAGE> 70

INDEX TO FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets as of December 31, 1998,
December 31, 1997 and March 31, 1999...................... F-3
Consolidated Statements of Operations for Each of the Three
Years in the Period Ended December 31, 1998 and the Three
Months Ended March 31, 1999 and 1998...................... F-4
Consolidated Statements of Stockholders' Equity for Each of
the Three Years in the Period Ended December 31, 1998 and
the Three Months Ended March 31, 1999..................... F-5
Consolidated Statements of Cash Flows for Each of the Three
Years in the Period Ended December 31, 1998 and the Three
Months Ended March 31, 1999 and 1998...................... F-6
Notes to Consolidated Financial Statements.................. F-7
</TABLE>

F-1
<PAGE> 71

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

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,
1998 and 1997, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. 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 generally accepted auditing
standards. 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, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.

/s/
ARTHUR ANDERSEN
New Orleans, Louisiana,
February 19, 1999

F-2
<PAGE> 72

CALLON PETROLEUM COMPANY

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
MARCH 31, ---------------------
1999 1998 1997
------------ --------- ---------
(UNAUDITED)
<S> <C> <C> <C>
Current assets:
Cash and cash equivalents............................... $ 4,150 $ 6,300 $ 15,597
Accounts receivable..................................... 5,688 6,024 12,168
Other current assets.................................... 1,648 1,924 723
--------- --------- ---------
Total current assets............................ 11,486 14,248 28,488
--------- --------- ---------
Oil and gas properties, full-cost accounting method:
Evaluated properties.................................... 462,871 444,579 398,046
Less accumulated depreciation, depletion and
amortization......................................... (349,236) (345,353) (282,891)
--------- --------- ---------
113,635 99,226 115,155
Unevaluated properties excluded from amortization....... 38,328 42,679 35,339
--------- --------- ---------
Total oil and gas properties.................... 151,963 141,905 150,494
--------- --------- ---------
Pipeline and other facilities, net........................ 6,102 6,182 6,504
Other property and equipment, net......................... 1,676 1,753 1,938
Deferred tax asset........................................ 16,105 16,348 1,248
Long-term gas balancing receivable........................ 191 199 242
Other assets, net......................................... 934 1,017 1,507
--------- --------- ---------
Total assets.................................... $ 188,457 $ 181,652 $ 190,421
========= ========= =========

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable and accrued liabilities................ $ 8,673 $ 11,257 $ 12,389
Undistributed oil and gas revenues...................... 1,874 1,720 2,259
Accrued net profits interest payable.................... 363 129 1,121
--------- --------- ---------
Total current liabilities....................... 10,910 13,106 15,769
--------- --------- ---------
Accounts payable and accrued liabilities to be
refinanced.............................................. 5,981 3,000 --
Long-term debt............................................ 86,250 78,250 60,250
Accrued retirement benefits............................... 2,269 2,323 297
Long-term gas balancing payable........................... 317 489 404
--------- --------- ---------
Total liabilities............................... 105,727 97,168 76,720
--------- --------- ---------
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares
authorized; 1,045,461 shares of Convertible
Exchangeable Preferred Stock, Series A issued and
outstanding at March 31, 1999 and 1,255,811 and
1,315,500 outstanding at December 31, 1998 and 1997,
respectively, with a liquidation preference of
$26,136,525 at March 31, 1999........................ 10 13 13
Common Stock, $.01 par value; 20,000,000 shares
authorized; 8,545,517, 8,178,406 and 7,855,216 shares
outstanding at March 31, 1999, December 1998 and
1997, respectively................................... 85 82 79
Treasury stock (98,577 shares at cost).................. (1,177) (915) --
Unearned compensation -- restricted stock............... -- -- (2,232)
Capital in excess of par value.......................... 108,296 109,429 106,433
Retained earnings (deficit)............................. (24,484) (24,125) 9,408
--------- --------- ---------
Total stockholders' equity...................... 82,730 84,484 113,701
--------- --------- ---------
Total liabilities and stockholders' equity...... $ 188,457 $ 181,652 $ 190,421
========= ========= =========
</TABLE>

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

F-3
<PAGE> 73

CALLON PETROLEUM COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
THREE MONTHS
ENDED MARCH 31, YEARS ENDED DECEMBER 31,
---------------- ----------------------------
1999 1998 1998 1997 1996
------ ------- -------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales.......................... $7,969 $11,045 $ 35,624 $42,130 $25,764
Interest and other......................... 405 447 2,094 1,508 946
------ ------- -------- ------- -------
Total revenues..................... 8,374 11,492 37,718 43,638 26,710
------ ------- -------- ------- -------
Cost and expenses:
Lease operating expenses................... 1,608 1,941 7,817 8,123 7,562
Depreciation, depletion and amortization... 3,963 5,570 19,284 16,488 9,832
General and administrative................. 1,061 1,502 5,285 4,433 3,495
Interest................................... 1,027 651 1,925 1,957 313
Accelerated vesting and retirement
benefits................................ -- -- 5,761 -- --
Impairment of oil and gas properties....... -- -- 43,500 -- --
------ ------- -------- ------- -------
Total costs and expenses........... 7,659 9,664 83,572 31,001 21,202
------ ------- -------- ------- -------
Income (loss) from operations................ 715 1,828 (45,854) 12,637 5,508
Income tax expense (benefit)............... 243 621 (15,100) 4,200 50
------ ------- -------- ------- -------
Net income (loss)............................ 472 1,207 (30,754) 8,437 5,458
Preferred stock dividends.................... 831 699 2,779 2,795 2,795
------ ------- -------- ------- -------
Net income (loss) available to common
shares..................................... $ (359) $ 508 $(33,533) $ 5,642 $ 2,663
====== ======= ======== ======= =======
Net income (loss) per common share:
Basic...................................... $ (.04) $ .06 $ (4.17) $ .91 $ .46
====== ======= ======== ======= =======
Diluted.................................... $ (.04) $ .06 $ (4.17) $ .88 $ .45
====== ======= ======== ======= =======
Shares used in computing net income (loss)
per common share:
Basic...................................... 8,477 8,015 8,034 6,194 5,835
====== ======= ======== ======= =======
Diluted.................................... 8,477 8,221 8,034 6,422 5,952
====== ======= ======== ======= =======
</TABLE>

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

F-4
<PAGE> 74

CALLON PETROLEUM COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)

<TABLE>
<CAPTION>
UNEARNED
COMPENSATION CAPITAL IN RETAINED
PREFERRED COMMON TREASURY RESTRICTED EXCESS OF EARNINGS
STOCK STOCK STOCK STOCK PAR VALUE (DEFICIT)
--------- ------ -------- ------------ ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1995.......... $13 $58 -- -- $ 73,955 $ 1,103
Net income......................... -- -- -- -- -- 5,458
Preferred stock dividends.......... -- -- -- -- -- (2,795)
Shares issued pursuant to employee
benefit plan.................... -- -- -- -- 72 --
--- --- ------- ------- -------- --------
Balances, December 31, 1996.......... 13 58 -- -- 74,027 3,766
Net income......................... -- -- -- -- -- 8,437
Sale of common stock............... -- 19 -- -- 29,249 --
Preferred stock dividends.......... -- -- -- -- -- (2,795)
Tax benefits related to stock
compensation plans.............. -- -- -- -- 36 --
Shares issued pursuant to employee
benefit and option plan......... -- -- -- -- 392 --
Restricted stock plan.............. -- 2 -- (3,153) 2,729 --
Earned portion of restricted
stock........................... -- -- -- 921 -- --
--- --- ------- ------- -------- --------
Balances, December 31, 1997.......... 13 79 -- (2,232) 106,433 9,408
Net income (loss).................. -- -- -- -- -- (30,754)
Preferred stock dividends.......... -- -- -- -- 15 (2,779)
Shares issued pursuant to employee
benefit and option plan......... -- -- -- -- 235 --
Employee stock purchase plan....... -- -- -- -- 163 --
Restricted stock plan.............. -- 2 -- (2,731) 2,584 --
Earned portion of restricted
stock........................... -- -- -- 4,963 -- --
Conversion of preferred shares to
common.......................... -- 1 -- -- (1) --
Stock buyback plan................. -- -- (915) -- -- --
--- --- ------- ------- -------- --------
Balances, December 31, 1998.......... 13 82 (915) -- 109,429 (24,125)
Net income (loss).................. -- -- -- -- -- 472
Preferred stock dividends.......... -- -- -- -- 276 (831)
Shares issued pursuant to employee
benefit and option plan......... -- -- -- -- 141 --
Employee stock purchase plan....... -- -- -- -- 66 --
Restricted stock plan.............. -- (2) -- -- (1,613) --
Earned portion of restricted
stock........................... -- -- -- -- -- --
Conversion of preferred shares to
common.......................... (3) 5 -- -- (3) --
Stock buyback plan................. -- -- (262) -- -- --
--- --- ------- ------- -------- --------
Balances, March 31, 1999
(Unaudited)........................ $10 $85 $(1,177) $ -- $108,296 $(24,484)
=== === ======= ======= ======== ========
</TABLE>

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

F-5
<PAGE> 75

CALLON PETROLEUM COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
THREE MONTHS
ENDED
MARCH 31, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
1999 1998 1998 1997 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)............................... $ 472 $ 1,207 $(30,754) $ 8,437 $ 5,458
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization..... 4,093 5,697 19,791 16,924 10,131
Impairment of oil and gas properties......... -- -- 43,500 -- --
Amortization of deferred costs............... 141 164 619 467 114
Deferred income tax expense (benefit)........ 243 621 (15,100) 4,200 50
Noncash compensation related to stock
compensation plans......................... 140 634 7,583 1,224 72
Changes in current assets and liabilities:
Accounts receivable........................ 336 1,946 6,144 493 (4,332)
Other current assets....................... 276 (1,004) (1,201) (207) (278)
Current liabilities........................ (2,462) (65) (860) (3,809) 4,049
Change in gas balancing receivable........... 8 (23) 43 418 (41)
Change in gas balancing payable.............. (172) 52 85 14 (42)
Change in other long-term liabilities........ (52) -- -- 249 (28)
Change in other assets, net.................. (58) (82) (129) (1,073) (830)
-------- -------- -------- -------- --------
Cash provided (used) by operating
activities................................. 2,965 9,147 29,721 27,337 14,323
-------- -------- -------- -------- --------
Cash flows from investing activities:
Capital expenditures............................ (13,884) (12,736) (64,105) (89,609) (37,637)
Cash proceeds from sale of mineral interests.... 154 339 9,909 4,450 1,574
-------- -------- -------- -------- --------
Cash provided (used) by investing
activities................................. (13,730) (12,397) (54,196) (85,159) (36,063)
-------- -------- -------- -------- --------
Cash flows from financing activities:
Change in accrued liabilities for capital
expenditures................................. -- -- (2,396) 3,610 3,346
Increase in accounts payable and accrued
liabilities to be refinanced................. 2,981 -- 3,000 -- --
Equity issued related to employee stock plans... 66 171 414 90 --
Purchase of treasury shares..................... (262) -- (915) -- --
Payments on debt................................ -- -- -- (49,200) (25,850)
Proceeds from debt issuance..................... 8,000 -- 18,000 85,200 50,000
Common stock canceled........................... (1,615) (145) (130) (422) --
Sale of common stock............................ -- -- -- 29,267 --
Increase (decrease) in accrued preferred stock
dividends payable............................ -- -- (16) -- 443
Dividends on preferred stock.................... (555) (699) (2,779) (2,795) (2,795)
-------- -------- -------- -------- --------
Cash provided (used) by financing
activities................................. 8,615 (673) 15,178 65,750 25,144
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents..................................... (2,150) (3,923) (9,297) 7,928 3,404
Cash and cash equivalents:
Balance, beginning of period.................... 6,300 15,597 15,597 7,669 4,265
-------- -------- -------- -------- --------
Balance, end of period.......................... $ 4,150 $ 11,674 $ 6,300 $ 15,597 $ 7,669
======== ======== ======== ======== ========
</TABLE>

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

F-6
<PAGE> 76

CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION WITH RESPECT TO THE PERIODS ENDING MARCH 31, 1999 AND 1998 IS
UNAUDITED.)

1. ORGANIZATION

Callon Petroleum Company (the "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 (the "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.

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 ("FAS 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. FAS
133 is effective for fiscal years beginning after June 15, 1999, with earlier
application permitted. The Company has not yet determined the timing or method
of the adoption of FAS 133 and thus cannot quantify the impact of adoption.
However, the Statement will create volatility in equity through other
comprehensive income.

In June 1997, the Financial Accounting Standards Board issued Statement No.
130 ("FAS 130"), Reporting Comprehensive Income. FAS 130 establishes standards
for reporting and display of comprehensive income and its components in a full
set of general purpose financial statements. FAS 130 was effective for the
Company in 1998. The Company does not have any items of other comprehensive
income.

Also in 1997, the Financial Accounting Standards Board issued Statement No.
131 ("FAS 131"), Disclosures about Segments of an Enterprise and Related
Information. FAS 131 establishes standards for

F-7
<PAGE> 77
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the way that public business enterprises report information about operating
segments in annual financial statements and requires that those enterprises
report selected information about operating segments in interim financial
reports issued to shareholders. The Company has only one operating segment and
thus separate segment disclosure is not required.

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. Costs associated with unevaluated
properties 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 of December 31, 1998 and 1997 and
March 31, 1999, estimated future site restoration, dismantlement and abandonment
costs, net of related salvage value and amounts funded by abandonment trusts
(see Notes 7 and 9) were not material.

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

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.

Derivatives

The Company uses derivative financial instruments (see Note 6) for price
protection purposes on a limited amount of its future production and does not
use them for trading purposes. Such derivatives are accounted for on an accrual
basis and amounts paid or received under the agreements are recognized as oil
and gas sales in the period in which they accrue.

F-8
<PAGE> 78
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Accounts Receivable

Accounts receivable consists primarily of accrued oil and gas production
receivable. The balance in the reserve for doubtful accounts included in
accounts receivable is $38,000, $38,000 and $36,000 at March 31, 1999, December
31, 1998 and 1997, respectively. Net recoveries were $2,000 in 1998 and net
charge offs were $357,000 and $88,000 in 1997 and 1996. There were no provisions
to expense in the three year period ended December 31, 1998 and the three month
period ending March 31, 1999.

For the year ended December 31, 1998, three companies purchased 23%, 26%
and 22%, respectively of the Company's natural gas and oil production. All three
customers purchased production primarily from Callon owned interests in Federal
OCS leases, CB40, MP163, MP 164/165, MB 864 and MB 952/955 fields. Because of
the nature of oil and gas operations and the marketing of production, the
Company believes that the loss of these customers would not have a significant
adverse impact on the Company's ability to sell its 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, 1998. During the years ended December 31, 1998, 1997 and 1996, the Company
made cash payments of $6,229,000, $4,167,000, and $251,000, respectively, for
interest charged on its indebtedness and $1,663,000 for the three months ended
March 31, 1999.

Per Share Amounts

In February 1997, the Financial Accounting Standards Board issued Statement
No. 128 ("FAS 128"), Earnings per Share, which generally simplified the manner
in which earnings per share are determined. The Company adopted FAS 128
effective December 15, 1997. In accordance with FAS 128, the Company's
previously reported earnings per share for 1996 were restated. The effect of
this accounting change on previously reported earnings per share (EPS) data was
as follows:

<TABLE>
<CAPTION>
1996
----
<S> <C>
Primary EPS as reported..................................... $.45
Effect of FAS 128........................................... .01
----
Basic EPS as restated....................................... $.46
====
Fully diluted EPS as reported............................... $.43
Effect of FAS 128........................................... .02
----
Diluted EPS as restated..................................... $.45
====
</TABLE>

Basic earnings or loss per common share were computed by dividing net
income or loss by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share for the years
1997 and 1996 were 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. In 1998, all
options were excluded from the computation of diluted loss per share because
they were antidilutive. The conversion of the preferred stock was not included
in any annual calculation due to their antidilutive effect on diluted income or
loss per share.

F-9
<PAGE> 79
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31, YEARS ENDED DECEMBER 31,
------------------ ----------------------------
1999 1998 1998 1997 1996
------- ------- -------- ------ ------
<S> <C> <C> <C> <C> <C>
(a) Net income (loss) available for common
stock.................................. $ (359) $ 508 $(33,533) $5,642 $2,663
(b) Weighted average shares outstanding.... 8,477 8,015 8,034 6,194 5,835
(c) Dilutive impact of stock options....... -- 206 -- 228 117
(d) Total diluted shares................... 8,477 8,221 8,034 6,422 5,952
Stock options excluded due to
antidilutive impact.................... 44 -- 163 -- --
Basic earnings (loss) per share(a/b)... $ (.04) $ .06 $ (4.17) $ .91 $ .46
Diluted earnings (loss) per
share(a/d)............................... $ (.04) $ .06 $ (4.17) $ .88 $ .45
</TABLE>

Fair Value of Financial Instruments

Fair value of cash, cash equivalents, accounts receivable, accounts payable
and long-term debt approximates book value at December 31, 1998 and 1997 and
March 31, 1999. Fair value of long-term debt (specifically the 10% and the
10.125% senior subordinated notes) was based on quoted market value.

The calculation of the fair market value of the outstanding hedging
contracts (see Note 6) as of December 31, 1998 indicated a $1.4 million market
value benefit to the Company based on market prices at that date.

Accounts Payable and Accrued Liabilities -- Long-Term

Approximately $3,000,000 and $6,000,000 of current accounts payable and
accrued liabilities at December 31, 1998 and March 31, 1999, respectively,
related to long-term assets, primarily oil and gas properties that were financed
subsequent to year-end with long-term debt and therefore have been reclassified
as long-term.

3. INCOME TAXES

The Company follows the asset and liability method of accounting for
deferred income taxes prescribed by Financial Accounting Standards Board
Statement No. 109 ("FAS 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

F-10
<PAGE> 80
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's management determined that no valuation allowance was necessary in
1998 and 1997. Accordingly, the Company has recorded a deferred tax asset at
December 31, 1998 and 1997 as follows:

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1998 1997
------- -------
(IN THOUSANDS)
<S> <C> <C>
Federal net operating loss carryforward..................... $ 7,916 $ 3,531
Statutory depletion carryforward............................ 4,083 4,062
Temporary differences:
Oil and gas properties.................................... 3,979 (4,943)
Pipeline and other facilities............................. (2,164) (2,277)
Non-oil and gas property.................................. (101) (86)
Other..................................................... 2,635 961
------- -------
Total tax asset............................................. 16,348 1,248
Valuation allowance......................................... -- --
------- -------
Net tax asset............................................... $16,348 $ 1,248
======= =======
</TABLE>

At December 31, 1998, the Company had, for federal tax reporting purposes,
net operating loss carryforwards ("NOL") of $22.6 million which expire in 2000
through 2012. Approximately $5.0 million of such carryovers are subject to
limitations on utilization as a result of ownership changes which occurred in
CPOC's common stock prior to the Consolidation and ownership changes as a result
of the Consolidation. Additionally, the Company had available for tax reporting
purposes $11.7 million in statutory depletion deductions which can be carried
forward for an indefinite period.

The provision for income taxes at the Company's effective tax rate differed
from the provision for income taxes at the statutory rate as follows:

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1998 1997 1996
-------- ------ -------
(IN THOUSANDS)
<S> <C> <C> <C>
Computed expense (benefit) at the expected statutory
rate.................................................. $(15,590) $4,296 $ 1,910
Change in valuation allowance........................... -- -- (1,760)
Other................................................... 490 (96) (100)
-------- ------ -------
Deferred income tax expense (benefit)................... $(15,100) $4,200 $ 50
======== ====== =======
</TABLE>

4. ACQUISITIONS

On June 26, 1997 the Company purchased an 18.8% working interest in the
Mobile Block 864 Area from Elf Exploration, Inc. The Company's net purchase
price was approximately $11.8 million. The Company further increased its
ownership in this area by purchasing Chevron U.S.A. Inc.'s interest in the
Mobile Block 864 Area for $18.8 million in November 1997.

The Company, together with an industry partner, was the high bidder on 18
offshore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157 and #161,
held during 1996 in New Orleans, Louisiana, and conducted by the U.S. Department
of the Interior through its Minerals Management Service ("MMS"). The Company
holds a 25% working interest in the leases and its share of the total lease
costs was approximately $15.2 million.

F-11
<PAGE> 81
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

5. LONG-TERM DEBT

Long-term debt consisted of the following at:

<TABLE>
<CAPTION>
DECEMBER 31,
MARCH 31, -----------------
1999 1998 1997
--------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Credit Facility......................................... $26,100 $18,100 $ 100
10% Senior Subordinated Notes........................... 24,150 24,150 24,150
10.125% Senior Subordinated Notes....................... 36,000 36,000 36,000
------- ------- -------
86,250 78,250 60,250
Less: current portion................................... -- -- --
------- ------- -------
$86,250 $78,250 $60,250
======= ======= =======
</TABLE>

Borrowings under the Credit Facility, with Chase Manhattan Bank, are
secured by mortgages covering substantially all of the Company's producing oil
and gas properties. Currently, the Credit Facility provides for a $50 million
borrowing base ("Borrowing Base") which is adjusted periodically on the basis of
a discounted present value of future net cash flows attributable to the
Company's proved producing oil and gas reserves. Pursuant to the Credit
Facility, depending upon the percentage of the unused portion of the borrowing
base, the interest rate is equal to the lender's prime rate plus 0.125% (prime
plus 0.50% if utilized percentage of borrowing base is greater than 50%). The
Company, at its option, may fix the interest rate on all or a portion of the
outstanding principal balance at 1.125% above a defined "Eurodollar" rate for
periods up to six months (1.5% above if utilized percentage of borrowing base is
greater than 50%). The weighted average interest rate for the total debt
outstanding at March 31, 1999, December 31, 1998 and 1997 was 6.50%, 6.68% and
8.50%, respectively. Under the Credit Facility, a commitment fee of .25% or
.375% per annum on the unused portion of the Borrowing Base (depending upon the
percentage of the unused portion of the Borrowing Base) is payable quarterly.
The Company may borrow, pay, reborrow and repay under the Credit Facility until
October 31, 2000, on which date, the Company must repay in full all amounts then
outstanding.

On November 27, 1996, the Company issued $24,150,000 of 10% Senior
Subordinated Notes that will mature December 15, 2001. The Company used the
proceeds to reduce borrowings under the Credit Facility and for other corporate
purposes. Interest is payable quarterly beginning March 15, 1997. The notes are
redeemable at the option of the Company, in whole or in part, on or after
December 15, 1997, at 100% of the principal amount thereof, plus accrued
interest to the redemption date. The notes are general unsecured obligations of
the Company, subordinated in right of payment to all existing and future
indebtedness of the Company.

On July 31, 1997, the Company issued $36 million of its 10.125% Series A
Senior Subordinated Notes due 2002. Interest is payable quarterly beginning
September 15, 1997. The Senior Subordinated Notes were offered through a private
placement transaction. The net proceeds of the transaction were used to repay
the outstanding balance under the Credit Facility and fund a portion of the
Company's capital expenditure budget. On September 10, 1997, the Company
commenced an offer to exchange the Series A Notes for a like principal amount of
10.125% Series B Senior Subordinated Notes due 2002 (the "Series B Notes" and,
together with the Series A Notes, the "10.125% Notes"). The form and terms of
the Series B Notes are identical in all material respects to the terms of the
Series A Notes, except for certain transfer restrictions and provisions relating
to registration rights. The exchange offer was completed on November 10, 1997.
Interest on the 10.125% Notes is payable quarterly, on March 15, June 15,
September 15, and December 15 of each year. The 10.125% Notes are redeemable at
the option of the Company in whole or in part, at any time on or after September
15, 2000. The 10.125% Notes are general

F-12
<PAGE> 82
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

unsecured obligations of the Company, subordinated in right of payment to all
existing and future indebtedness of the Company and rank pari passu with the 10%
Notes.

The Credit Facility and the subordinated debt 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, 1998 and March 31, 1999.

6. HEDGING CONTRACTS

The Company periodically uses derivative financial instruments to manage
oil and gas price risk. Settlements of gains and losses on commodity price swap
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, and are reported as a component of oil and gas revenues.
Gains or losses attributable to the termination of a swap contract are deferred
and recognized in revenue when the oil and gas production is sold. Approximately
$1,886,000 and $2,466,000 was recognized as additional oil and gas revenue in
1998 and 1997 and recognized a reduction in revenue of $2,757,000 in 1996 as a
result of such agreements. For the three months ended March 31, 1999 and 1998,
approximately $1,004,000 and $583,000 was recognized as additional oil and gas
revenue, respectively.

At March 31, 1999, the Company had open collar contracts with third parties
whereby minimum floor prices and maximum ceiling prices are contracted and
applied to related contract volumes. These agreements in effect for 1999 are for
average gas volumes of 483,333 Mcf per month through September 1999 at (on
average) a ceiling price of $2.12 and floor price of $1.85. In addition, the
Company had open oil collar contracts averaging 24,167 barrels per month at (on
average) a ceiling of $16.15 and a floor of $13.78 from April 1999 through
December 1999.

Also at March 31, 1999 the Company had open forward natural gas swap
contracts of 200,000 Mcf per month from April 1999 through September 1999 with a
fixed contract price of $2.35. In addition, the Company had open forward crude
oil swap contracts of 10,000 barrels per month with a fixed contract price of
$14.10 per month from April 1999 through June 1999.

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 March 31, 1999, total estimated site
restoration, dismantlement and abandonment costs were approximately $6,000,000,
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.

The Company, as part of the Consolidation, entered into Registration Rights
Agreements whereby the former stockholders of certain of the Constituent
Entities 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 a firm commitment public offering 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 discounts and commissions, which will be
paid by the respective sellers of the Common Stock.

F-13
<PAGE> 83
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

<TABLE>
<CAPTION>
THREE MONTHS
ENDED YEARS ENDED DECEMBER 31,
MARCH 31, ------------------------------
1999 1998 1997 1996
------------ -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Capitalized costs incurred:
Evaluated Properties --
Beginning of period balance................ $444,579 $398,046 $322,970 $304,737
Property acquisition costs................. 348 9,464 51,751 2,999
Exploration costs.......................... 15,905 42,617 13,620 8,732
Development costs.......................... 1,885 4,361 14,155 8,076
Sale of mineral interest................... 154 (9,909) (4,450) (1,574)
-------- -------- -------- --------
End of period balance...................... $462,871 $444,579 $398,046 $322,970
======== ======== ======== ========
Unevaluated Properties (excluded from the
full-cost pool) --
Beginning of period balance................ $ 42,679 $ 35,339 $ 26,235 $ 10,171
Additions.................................. 1,891 11,156 16,924 20,640
Capitalized interest and general
administrative costs..................... 1,613 8,955 5,163 1,883
Transfer to evaluated...................... (7,855) (12,771) (12,983) (6,459)
-------- -------- -------- --------
End of period balance...................... 38,328 $ 42,679 $ 35,339 $ 26,235
======== ======== ======== ========
Accumulated depreciation, depletion and
amortization --
Beginning of period balance................ $345,353 $282,891 $266,716 $257,143
Provision charged to expense............... 3,883 18,962 16,175 9,573
Impairment of oil and gas properties....... -- 43,500 -- --
-------- -------- -------- --------
End of period balance...................... $349,236 $345,353 $282,891 $266,716
======== ======== ======== ========
</TABLE>

Unevaluated property costs, primarily lease acquisition costs incurred at
federal and state lease sales and unevaluated drilling costs being excluded from
the amortizable evaluated property base as of December 31, 1998 consisted of
$17.9 million incurred in 1998, $8.2 million incurred in 1997 and $16.6 million
incurred in 1996 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 majority of these costs will be evaluated over the next five
year period.

Depreciation, depletion and amortization per unit-of-production (equivalent
barrel of oil) amounted to $7.16, $6.11, and $5.87 for the years ended December
31, 1998, 1997 and 1996, respectively, and $5.96 and $6.99 for the three months
ended March 31, 1999 and 1998, respectively.

Impairment of Oil and Gas Properties

Under full-cost accounting rules, the capitalized costs of proved oil and
gas properties are subject to a "ceiling test", which limits such costs to the
estimated present value net of related tax effects, discounted at a 10 percent
interest rate, of future net cash flows from proved reserves, based on current
economic and

F-14
<PAGE> 84
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

operating conditions (PV-10). If capitalized costs exceed this limit, the excess
is charged to expense. During the fourth quarter of 1998, the Company recorded a
noncash impairment provision related to oil and gas properties in the amount of
$43.5 million ($28.7 million after-tax) primarily due to the significant decline
in oil and gas prices.

9. NET PROFITS INTEREST

Since 1989, the Constituent Entities have 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,
1998 and 1997 the Trusts' assets (all cash and investments) totaled $6,360,000
and $19,300,000, respectively and $6,000,000 at March 31, 1999, 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. The
trust asset decrease in 1998 was the result of a sale of an oil and gas property
and the related trust.

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
owner's 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.

F-15
<PAGE> 85
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 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 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 $468,000, $438,000, and $241,000 in
the years 1998, 1997 and 1996, respectively.

The 1994 Stock Incentive Plan (the "1994 Plan") 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. No options will be granted at an
exercise price of less than fair market value of the Common Stock on the date of
grant. A total of 500,000 options were granted in 1994 and 1995 and all such
options could be exercised as of December 31, 1996. During 1997, there were no
other options granted and 9,000 shares were exercised at an average price of
$17.94. These options have an expiration date 10 years from date of grant. In
1998, 20,000 non-employee director options were granted under the plan, vesting
100% in November 1998.

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 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.
During 1998, 1997 and 1996, the Company granted stock options to purchase
205,000, 20,000 and 530,000 shares, respectively, of Common Stock under the
plan. All of such options were granted at an exercise price equal to the fair
market value of the Common Stock on the date of grant. Terms of the options
granted in 1998 provide that 25% of the options become exercisable each year
beginning August of 1998 and each succeeding January. Terms of the plan for
450,000 options granted in 1996 provide that 20% of the options become
exercisable on January 1 of each succeeding year, beginning January 1, 1997.
Non-employee director options aggregating 80,000 shares vest 25% at each
succeeding annual meeting of directors following each annual stockholders'
meeting, beginning in 1997. Unvested options are subject to forfeiture upon
certain termination of employment events and expire 10 years from date of grant.

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. Had compensation cost for these

F-16
<PAGE> 86
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

plans been determined consistent with FAS 123, the Company's net income and
earnings per common share would have been reduced to the following pro forma
amounts:

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------------
1998 1997 1996
---------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
<S> <C> <C> <C>
Net income (loss):
As reported............................................ $(33,533) $5,642 $2,663
Pro Forma.............................................. (34,421) 4,977 2,411
Basic earnings (loss) per share:
As reported............................................ (4.17) .91 .46
Pro Forma.............................................. (4.28) .80 .41
Diluted earnings (loss) per share:
As reported............................................ (4.17) .88 .45
Pro Forma.............................................. (4.28) .77 .41
</TABLE>

Because the Statement 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost above may not be representative of that to be expected in future years.

A summary of the status of the Company's two stock option plans at December
31, 1998, 1997 and 1996 and changes during the years then ended is presented in
the table and narrative below:

<TABLE>
<CAPTION>
1998 1997 1996
--------------------- --------------------- ---------------------
WTD WTD WTD
AVG AVG AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
---------- -------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding, beginning of
year........................ 1,041,000 $11.19 1,030,000 $11.10 490,000 $10.01
Granted..................... 225,000 10.08 20,000 15.31 550,000 12.06
Exercised................... -- -- (9,000) 10.00 -- --
Forfeited................... -- -- -- -- (10,000) 10.00
Expired..................... -- -- -- -- -- --
---------- ------ ---------- ------ ---------- ------
Outstanding, end of year...... 1,266,000 $11.00 1,041,000 $11.19 1,030,000 $11.10
========== ====== ========== ====== ========== ======
Exercisable, end of year...... 802,250 $10.90 621,000 $10.65 500,000 $10.16
========== ====== ========== ====== ========== ======
Weighted average fair value of
options granted............. $ 4.31 $ 6.30 $ 4.96
========== ========== ==========
</TABLE>

The options outstanding at December 31, 1998 have exercise prices ranging
from $9.47 to $16.38 with a remaining weighted average contractual life of 7.06
years.

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 1998, 1997 and 1996.

<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Risk free interest rate..................................... 5.1% 6.8% 6.5%
Expected life (years)....................................... 7.0 4.0 4.9
Expected volatility......................................... 28.8% 41.1% 34.7%
Expected dividends.......................................... -- -- --
</TABLE>

F-17
<PAGE> 87
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company awarded 225,000 performance shares under the 1996 Plan to the
Company's Executive officers on August 23, 1996. During June 1997, the Company's
stockholders approved the performance share awards and the related common stock
was issued. The issuance was recorded at the fair market value of the shares on
their date of grant, with a corresponding charge to stockholders' equity
representing the unearned portion of the award. All of the performance shares
granted will vest in whole on January 1, 2001, and will be subject to forfeiture
upon certain termination of employment events. The unearned portion was being
amortized as compensation expense on a straight-line basis over the vesting
period. An additional 25,000 shares were issued under the 1994 Plan in 1997 and
165,500 shares were issued to certain key employees other than the Company's
Executive officers in 1998. Approximately $4,963,000 in 1998, $714,000 in 1997
and $208,000 in 1996 of compensation cost were charged to expense related to the
restricted shares granted.

In December 1998, the Company approved the accelerated vesting of all
performance shares. As a result, an additional charge of $3,469,000 which
represents the future unamortized expense related to unvested shares at the date
the acceleration of vesting occurred, was expensed in 1998.

In addition, the Company recorded a provision of approximately $2.3 million
for retirement benefits approved in December of 1998.

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"). 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 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.

On November 25, 1997, the Company completed a public offering of 1,840,000
shares of Common Stock at a price to the public of $17.00. This offering
resulted in the Company receiving cash proceeds of $29,267,000, net of offering
costs and underwriting discount. The Company used a portion of the proceeds to
repay indebtedness incurred to finance the purchase of Chevron U.S.A. Inc.'s
interest in Mobile Block 864 Area (see Note 4) and the remaining proceeds were
used to fund a portion of the 1998 capital expenditures budget.

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. During the first quarter of 1999 certain preferred stockholder's
through private transactions, agreed to convert 210,350 shares of Preferred
Stock into 502,632 shares of the Company's Common Stock. Any premium negotiated
in excess of the conversion rate was recorded as additional preferred stock
dividends.

F-18
<PAGE> 88
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)

The Company's proved oil and gas reserves at December 31, 1998, 1997 and
1996 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.

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 present values 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.

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

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1998 1997 1996
------- ------- ------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period.................................... 3,402 3,819 4,766
Revisions to previous estimates........................ (99) (151) (50)
Purchase of reserves in place.......................... 162 -- --
Sales of reserves in place............................. (1,531) (78) (312)
Extensions and discoveries............................. 5,274 274 --
Production............................................. (310) (462) (585)
------- ------- ------
End of period.......................................... 6,898 3,402 3,819
======= ======= ======
Natural Gas (MMcf):
Beginning of period.................................... 88,738 50,424 29,667
Revisions to previous estimates........................ (8,631) (11,174) (1,688)
Purchase of reserves in place.......................... 4,414 52,485 7,391
Sales of reserves in place............................. (684) (164) (228)
Extensions and discoveries............................. 18,229 10,281 21,551
Production............................................. (14,036) (13,114) (6,269)
------- ------- ------
End of period.......................................... 88,030 88,738 50,424
======= ======= ======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period.................................... 2,976 3,385 3,890
======= ======= ======
End of period.......................................... 1,774 2,976 3,385
======= ======= ======
Natural Gas (MMcf):
Beginning of period.................................... 88,010 49,491 20,408
======= ======= ======
End of period.......................................... 76,895 88,010 49,491
======= ======= ======
</TABLE>

F-19
<PAGE> 89
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 at each date presented and have been escalated only when known and
determinable price changes are provided by contract and law. Future production,
development and net abandonment costs are based on current costs without
escalation. The resulting net future cash flows have been discounted to their
present values based on a 10% annual discount factor.

STANDARDIZED MEASURE

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows......................................... $256,325 $285,953 $285,727
Future costs --
Production................................................ (67,192) (63,709) (59,584)
Development............................................... (36,581) (12,984) (9,989)
-------- -------- --------
Future net inflows before income taxes...................... 152,552 209,260 216,154
Future income taxes......................................... -- (32,781) (49,438)
-------- -------- --------
Future net cash flows....................................... 152,552 176,479 166,716
10% discount factor......................................... (52,801) (48,400) (36,547)
-------- -------- --------
Standardized measure of discounted future net cash flows.... $ 99,751 $128,079 $130,169
======== ======== ========
</TABLE>

CHANGES IN STANDARDIZED MEASURE

<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure -- beginning of period................. $128,079 $130,169 $ 63,764
Sales and transfers, net of production costs................ (27,807) (34,006) (18,202)
Net change in sales and transfer prices, net of production
costs..................................................... (33,029) (66,880) 32,268
Exchange and sale of in place reserves...................... (4,445) (2,428) (877)
Purchases, extensions, discoveries, and improved recovery,
net of future production and development costs............ 24,294 90,550 79,983
Revisions of quantity estimates............................. (9,409) (13,751) (3,907)
Accretions of discount...................................... 13,645 16,017 6,376
Net change in income taxes.................................. 7,926 21,633 (30,000)
Changes in production rates, timing and other............... 497 (13,225) 764
-------- -------- --------
Standardized measure -- end of period....................... $ 99,751 $128,079 $130,169
======== ======== ========
</TABLE>

F-20
<PAGE> 90
CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
1998
Total revenues.......................................... $11,492 $9,733 $9,339 $ 7,154
Total costs and expenses................................ 9,664 8,606 7,919 57,383
Income taxes expense (benefit).......................... 621 380 487 (16,588)
Net income (loss)....................................... 1,207 747 933 (33,641)
Net income (loss) per share -- basic.................... .06 .01 .03 (4.27)
Net income (loss) per share -- diluted.................. .06 .01 .03 (4.27)
1997
Total revenues.......................................... $12,781 $8,758 $9,201 $ 12,898
Total costs and expenses................................ 7,366 6,971 7,394 9,270
Income taxes expense.................................... 1,733 578 615 1,274
Net income.............................................. 3,682 1,209 1,192 2,354
Net income (loss) per share -- basic.................... .50 .08 .08 .25
Net income (loss) per share -- diluted.................. .39 .08 .08 .24
</TABLE>

F-21
<PAGE> 91

[Photograph of the Ocean Concord,
the drilling rig that drilled the Habanero prospect.]

During the first quarter of 1999, the Ocean Concord (pictured above)
successfully drilled the largest discovery in our history. Located in 2,000 feet
of water at Garden Banks Block 341, the Habanero prospect was drilled to a
measured depth of 21,158 feet and encountered over 200 net feet of pay in two
zones.

<PAGE> 92

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

WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT
CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION
OR REPRESENTATIONS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR SALE OF THE
NOTES MEANS THAT INFORMATION CONTAINED IN THIS PROSPECTUS IS CORRECT AFTER THE
DATE OF THIS PROSPECTUS. THIS PROSPECTUS IS NOT AN OFFER TO SELL OR SOLICITATION
OF AN OFFER TO BUY THESE NOTES IN ANY CIRCUMSTANCES UNDER WHICH THE OFFER OR
SOLICITATION IS UNLAWFUL.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary...................... 3
Risk Factors............................ 9
Forward-Looking Statements.............. 14
Use of Proceeds......................... 15
Capitalization.......................... 15
Selected Financial Data................. 16
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................ 18
Business and Properties................. 25
Management.............................. 38
Beneficial Ownership of Our Common and
Preferred Stock....................... 40
Description of the Notes................ 44
Description of Bank Credit Facility and
Other Indebtedness.................... 61
Description of Capital Stock............ 62
Underwriting............................ 64
Validity of the Notes................... 65
Experts................................. 65
Where You Can Find More Information..... 65
Glossary of Oil and Gas Terms........... 67
Index to Financial Statements........... F-1
</TABLE>

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- ---------------------------------------------------------
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$40,000,000
LOGO
CALLON PETROLEUM COMPANY
10.25% SENIOR SUBORDINATED NOTES
DUE 2004
------------------------

PROSPECTUS
------------------------
A.G. EDWARDS & SONS, INC.

MORGAN KEEGAN & COMPANY, INC.
July 14, 1999

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