CALLON PETROLEUM CO, 424B1, 1997-11-25

CALLON PETROLEUM CO
424B1, 1997-11-25
CRUDE PETROLEUM & NATURAL GAS

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Filed Pursuant to Rule 424(b)(1)
Registration Statement No. 333-39401

PROSPECTUS

1,600,000 SHARES
[LOGO] CALLON PETROLEUM COMPANY
COMMON STOCK
------------------------

All 1,600,000 shares (the "Shares") of Common Stock, par value $.01 per
share (the "Common Stock"), of Callon Petroleum Company ("Callon" or the
"Company") offered hereby (the "Offering") are being sold by the Company.

The Common Stock is traded on the Nasdaq National Market ("Nasdaq") under
the symbol "CLNP." On November 24, 1997, the last sale price of the Common
Stock as reported on Nasdaq was $18 1/2 per share. See "Price Range of Common
Stock and Dividend Policy."

SEE "RISK FACTORS" BEGINNING ON PAGE 10 FOR A DISCUSSION OF CERTAIN
MATTERS THAT SHOULD BE CONSIDERED BY POTENTIAL INVESTORS.

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY
IS A CRIMINAL OFFENSE.

UNDERWRITING PROCEEDS TO
PRICE TO PUBLIC DISCOUNT(1) COMPANY(2)
--------------- --------------------- ------------------------
Per share.... $17.00 $0.935 $16.065
Total(3)..... $27,200,000 $1,496,000 $25,704,000

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

(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended (the "Securities Act"). See "Underwriting."

(2) Before deducting estimated offering expenses of $500,000 payable by the
Company.

(3) The Company has granted the Underwriters an over-allotment option,
exercisable for 30 days from the date of this Prospectus, to purchase up to
an additional 240,000 shares of Common Stock from the Company solely to
cover over-allotments. If all such shares are purchased by the Underwriters,
the total Price to Public, Underwriting Discount and Proceeds to Company
will be $31,280,000, $1,720,400 and $29,559,600, respectively. See
"Underwriting."
------------------------

The Shares are offered by the Underwriters, subject to prior sale, when, as
and if issued to and accepted by them, and subject to certain other conditions.
The Underwriters reserve the right to withdraw, cancel or modify such offer and
to reject orders in whole or in part. It is expected that delivery of the Shares
will be made on or about December 1, 1997.
------------------------

MORGAN KEEGAN & COMPANY, INC.
A.G. EDWARDS & SONS, INC.
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
JEFFERIES & COMPANY, INC.

The date of this Prospectus is November 25, 1997.
<PAGE>
CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING OVER-ALLOTMENT, STABILIZING TRANSACTIONS, SYNDICATE SHORT COVERING
TRANSACTIONS AND IMPOSING PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES,
SEE "UNDERWRITING."

IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY ENGAGE IN PASSIVE
MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON THE NASDAQ NATIONAL MARKET IN
ACCORDANCE WITH RULE 103 OF REGULATION M UNDER THE SECURITIES EXCHANGE ACT OF
1934, AS AMENDED (THE "EXCHANGE ACT"). SEE "UNDERWRITING."

<PAGE>
PROSPECTUS SUMMARY

THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY, AND SHOULD BE READ
IN CONJUNCTION WITH, THE MORE DETAILED INFORMATION AND CONSOLIDATED FINANCIAL
STATEMENTS AND THE NOTES THERETO APPEARING ELSEWHERE HEREIN. UNLESS OTHERWISE
INDICATED, THE INFORMATION IN THIS PROSPECTUS ASSUMES THAT THE UNDERWRITERS'
OVER-ALLOTMENT OPTION WILL NOT BE EXERCISED. UNLESS OTHERWISE INDICATED, PRO
FORMA INFORMATION GIVES EFFECT TO THE ELF ACQUISITION (AS DEFINED), THE CHEVRON
ACQUISITION (AS DEFINED) AND THE OFFERING AS IF THEY OCCURRED ON THE DATE OR AS
OF THE BEGINNING OF THE EARLIEST PRO FORMA PERIOD INDICATED. CERTAIN TERMS
RELATING TO THE OIL AND GAS INDUSTRY ARE DEFINED IN "GLOSSARY."

THE COMPANY

Callon Petroleum Company has been engaged in the acquisition, development,
exploration and production of oil and gas since 1950. The Company's properties
are geographically concentrated offshore in the Gulf of Mexico and onshore in
Louisiana and Alabama. As of October 31, 1997, on a pro forma basis, the Company
had estimated net proved reserves of 118.0 Bcfe with a PV-10 Value of $194.2
million, representing increases of 61% and 21%, respectively, from December 31,
1996. Approximately 93% of these pro forma reserves are proved developed.
Average daily production during the first nine months of 1997 was 42.1 MMcfe/d,
representing an increase of 54% over the first nine months of 1996.

Since 1995, the Company has increasingly supplemented its acquisition of
producing properties with exploration and development drilling in the Gulf of
Mexico. Between January 1, 1995 and October 31, 1997, Callon accomplished the
following:

o Increased pro forma estimated net proved reserves to 118.0 Bcfe
from 50.6 Bcfe at a Reserve Replacement Cost of $1.07 per Mcfe.

o Increased the pro forma PV-10 Value of estimated net proved
reserves to $194.2 million from $41.4 million.

o Completed 14 acquisitions of properties with estimated net proved
reserves of 80.4 Bcfe for a total acquisition cost of $68.4
million, or $0.85 per Mcfe, on a pro forma basis.

o Spent $14.2 million to drill and complete 3 exploratory wells and
12 development wells, which added estimated net proved reserves of
27.8 Bcf.

o Assembled an inventory of 37 exploration prospects in the Gulf of
Mexico which remain to be drilled.

o Increased EBITDA to $16.1 million in 1996 from $6.7 million in
1994. For the first nine months of 1997, EBITDA rose 90% to $21.9
million compared with the first nine months of 1996.

o Increased earnings per share to $0.45 in 1996 compared to a loss of
$0.03 per share in 1994. Earnings per share for the first nine
months of 1997 rose 215% to $0.63 compared with the first nine
months of 1996.

BUSINESS STRATEGY

The Company's objective is to enhance shareholder value through sustained
growth in its reserve base, production levels, and resulting cash flow from
operations. In furtherance of this strategy, the Company (i) acquires properties
with exploration and development potential; (ii) utilizes advanced technology,
including proprietary high resolution, shallow focus seismic technology and the
latest available 3-D seismic surveys; (iii) balances lower risk, shallow target
exploration in the Shallow Miocene Trend and similar geologic areas with higher
risk, large target exploration; and (iv) acquires properties which provide it
with the ability to control or significantly influence operations.

3
<PAGE>
EXPLORATION AND DEVELOPMENT ACTIVITIES

The Company currently conducts its exploration and development activities
in three areas, the Shallow Miocene Trend, the Main Pass Block 32/35 Area and in
various areas in a joint venture with Murphy Oil Corporation ("Murphy").

THE SHALLOW MIOCENE TREND. The Company conducts exploration and
development activities in the Shallow Miocene Trend in the Gulf of Mexico, where
it seeks oil and gas deposits located near existing production facilities at
true vertical depths of between 1,800 and 6,000 feet. Relatively low exploration
and development costs and high initial production rates characterize successful
wells in this area. The Company has successfully used high-resolution, shallow
focused seismic techniques to explore for and develop these shallow gas
deposits. These seismic techniques utilize high-definition two dimensional
seismic lines shot in a tight grid, with spacing as close as 50 meters. The
Company has developed a proprietary method of processing and interpreting this
data which the Company believes gives it a competitive advantage over other
companies exploring in the Shallow Miocene Trend. During 1996, the Company
completed four proprietary high-resolution seismic surveys over an eight block
area contiguous to Chandeleur Block 40. Based on these surveys, between October
1996 and July 1997, the Company drilled 2 gross (1.5 net) successful development
wells, 2 gross (2.0 net) successful exploratory wells and one unsuccessful (0.7
net) development well in this area for a drilling success rate of 80%. Primarily
as a result of these wells, the Company's average daily production for the first
nine months of 1997 increased to 42.1 MMcfe/d, a 54% increase over the same
period of 1996. The Company intends to use this high-resolution seismic
technique to confirm 3-D seismic surveys of shallow gas prospects on its Brazos
Blocks 582 and 610 in the Gulf of Mexico. Through year end 1998, the Company's
budget includes drilling 3 gross (2.4 net) exploration wells and 2 gross (1.2
net) development wells in the Shallow Miocene Trend and Brazos Blocks 582 and
610, for a total net dry hole cost of $10.9 million, excluding completion and
development costs.

MAIN PASS 32/35 AREA. In the Main Pass Block 32/35 Area, the Company owns
and operates 14 producing wells in a field located in shallow Louisiana-state
waters which produce from true vertical depths of between 6,000 and 9,000 feet.
In November 1996, the Company completed a 36 square-mile 3-D seismic survey
covering its Main Pass Block 35 field and adjoining acreage. Based upon this
data, the Company farmed-in and successfully drilled a development well to a
total depth of 10,900 feet in August 1997, which added estimated net proved
reserves as of October 31, 1997 of 7.7 Bcfe. The Company also acquired
additional acreage in this area and entered into a joint venture agreement with
Burlington Resources Oil & Gas Company to drill eight prospects identified by
the 3-D seismic survey at true vertical depths of between 13,000 and 15,000
feet. The Company will operate and has retained an approximate 42.4% working
interest in wells drilled on these prospects. Through 1998, the Company's budget
includes drilling 7 gross (3.0 net) exploration wells and 3 gross (0.9 net)
development wells in the Main Pass Block 32/35 Area for a total net dry hole
cost of $11.4 million, excluding completion and development costs.

THE MURPHY JOINT VENTURE. The Company has also entered into an agreement
with Murphy to jointly explore 32 blocks in the Gulf of Mexico, primarily in
shallow waters seeking deposits to true vertical depths of 17,500 feet. In
September 1997, the Company and Murphy drilled a successful exploration well on
Eugene Island Block 335 to a total vertical depth of 6,094 feet. As of October
31, 1997, the Eugene Island Block 335 field had estimated proved reserves of 5.8
Bcfe, net to Callon. During November 1997, the Company drilled a successful
sidetrack well to a measured depth of 6,330 feet. The Company is currently
drilling a third well in the field.

The Company and Murphy have generated an additional 18 prospects in the
shallow waters of the Gulf of Mexico, to explore for oil and gas deposits at
true vertical depths of between 8,000 and 17,500 feet. The Company owns either a
20% or 25% working interest in each of these prospects. The Company's budget
through 1998 includes the drilling of 8 gross (1.9 net) exploration wells and
one gross (0.2 net) development well on eight of these prospects, for a total
net dry hole cost of $8.9 million, excluding completion and development costs.

4
<PAGE>
The Company and Murphy have also acquired acreage and generated five
prospects in the deep waters of the Gulf of Mexico. The Company plans to drill
an exploration well with Murphy in 900 feet of water during the fourth quarter
of 1997. Estimated dry hole costs to drill this well are $2.2 million, net to
Callon.

In total, the Company's current capital budget through fiscal 1998 of $85.6
million contemplates the drilling of 6 gross (2.2 net) development wells and 19
gross (7.5 net) exploratory wells, at an estimated net dry hole cost to the
Company of $33.4 million and $52.2 million in completion and development costs.
These drilling operations will be financed through cash flows from operations,
the net proceeds of this Offering, the proceeds of property sales and borrowings
under the Company's credit facility with a commercial bank ("Credit
Facility"). The Company's Credit Facility had an available borrowing base of
$40 million as of September 30, 1997. See "Use of Proceeds."

RECENT DEVELOPMENTS

During 1997, the Company focused its acquisition efforts in the Shallow
Miocene Trend in the Mobile Block 864 Area located offshore Alabama. During the
first nine months of 1997, Callon consummated three acquisitions in this area
and in October 1997 agreed to acquire properties also located in this area from
Chevron U.S.A. Inc. In October 1997, the Company also entered into a letter of
intent to sell properties in its Black Bay Complex.

RECENT ACQUISITIONS. In June 1997, the Company closed an $11.8 million
acquisition from Elf Exploration, Inc. (the "Elf Acquisition") for their
interest in three adjoining blocks located in the Shallow Miocene Trend in
federal waters in the Mobile Block 864 Area. In August 1997, for $7.5 million
Callon acquired from Koch Exploration Company (the "Koch Acquisition") an
interest in two wells producing from the Shallow Miocene Trend adjoining the
blocks acquired in the Elf Acquisition. Additionally, in September 1997, at a
purchase price of $10.6 million the Company acquired from Santa Fe Energy
Resources, Inc. additional interests in the properties acquired in the Koch
Acquisition, along with an interest in a well in a nearby block. In total, the
Company spent $29.9 million to acquire properties in the Mobile Block 864 Area
which as of October 31, 1997, had estimated net proved reserves of 32 Bcfe. The
Company's average net daily production during September 1997 from this area was
6.9 MMcf/d.

In October 1997, the Company agreed to purchase 61% of Chevron U.S.A.
Inc.'s interest in the Mobile Block 864 Area for $21 million, effective July 1,
1997 (the "Chevron Acquisition"). As of October 31, 1997, estimated net proved
reserves attributable to the Chevron Acquisition were 18.6 Bcfe. The Chevron
Acquisition closed on November 7, 1997 for a net acquisition cost of $18.8
million. As a result of this acquisition, the Company will have acquired an
average 55.4% working interest in seven blocks, a 53.3% working interest in the
Mobile Block 864 Area unit and the unit production facilities, a 66.7% working
interest in two producing wells and a 50% working interest in another well. The
Company became the operator of the unit representing approximately 57% of its
estimated net proved reserves in the Mobile Block 864 Area as of October 31,
1997 on an Mcfe basis, and related production facilities.

The Company has identified two development prospects and one exploration
prospect in the Mobile Block 864 Area. Following the Chevron Acquisition, the
Company plans to conduct an extensive shallow focus, high-resolution seismic
survey over the area to refine its development plans and to explore for
additional prospects. Production from the area is currently limited by the
capacity of the production facilities, which the Company intends to increase
during 1998.

SALE OF BLACK BAY COMPLEX. The Company has entered into a letter of intent
to sell its interest in the Black Bay Complex which will net the Company an
estimated $11.4 million (including amounts released to the Company previously
placed in escrow to cover abandonment costs).

5
<PAGE>
THE OFFERING

Common Stock offered by the Company.....1,600,000 shares

Common Stock to be outstanding after
the Offering..........................7,628,994(1)

Use of Proceeds.........................The net proceeds of the Offering will be
utilized to repay indebtedness incurred
to finance the Chevron Acquisition and
to fund a portion of the Company's 1997
and 1998 capital expenditure budget.
Prior to the utilization of the net
proceeds, the Company will invest such
funds in short-term investments.

Nasdaq Symbol..........................."CLNP"

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

(1) Excludes 1,044,000 shares of Common Stock issuable upon exercise of stock
options outstanding as of September 30, 1997, at a weighted average exercise
price of $11.19. Also excludes 2,990,132 shares reserved for issuance
pursuant to the Company's $2.125 Convertible Preferred Stock with a
conversion price of $11 per share. Includes 225,000 performance shares
issued under the Callon Petroleum Company 1996 Stock Incentive Plan which do
not vest until January 1, 2001 and 25,000 restricted shares issued in 1997
under the Callon Petroleum Company 1994 Stock Incentive Plan which vest 20%
annually beginning January 2, 1998.

6
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------------------------- ---------------------------------------------
1997 1996 1996 1995 1994
---------------------------- --------- ---------------------- --------- ---------
PRO
FORMA PRO
AS ADJUSTED(1) HISTORICAL FORMA(1) HISTORICAL
-------------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA(2):
Revenues:
Oil and gas sales.............. $ 36,058 $ 29,578 $ 18,578 $38,954 $ 25,764 $ 23,210 $ 13,948
Interest and other............. 1,162 1,162 537 946 946 627 171
-------------- ---------- --------- -------- ---------- --------- ---------
Total revenues............. 37,220 30,740 19,115 39,900 26,710 23,837 14,119
-------------- ---------- --------- -------- ---------- --------- ---------
Costs and Expenses:
Lease operating expenses....... 6,219 6,235 5,646 8,102 7,562 6,732 4,042
Depreciation, depletion and
amortization................. 14,169 11,288 7,697 14,744 9,832 10,376 6,049
General and administrative..... 3,263 3,263 2,352 3,495 3,495 3,880 3,717
Interest....................... 1,496 945 184 1,861 313 1,794 624
-------------- ---------- --------- -------- ---------- --------- ---------
Total costs and
expenses................. 25,147 21,731 15,879 28,202 21,202 22,782 14,432
-------------- ---------- --------- -------- ---------- --------- ---------
Income (loss) from operations....... 12,073 9,009 3,236 11,698 5,508 1,055 (313)
Provision (benefit) for income
taxes............................. 4,225 2,926 -- 4,094 50 -- (200)
-------------- ---------- --------- -------- ---------- --------- ---------
Net income (loss)................... 7,848 6,083 3,236 7,604 5,458 1,055 (113)
Preferred stock dividends........... 2,097 2,097 2,097 2,795 2,795 256 --
-------------- ---------- --------- -------- ---------- --------- ---------
Net income (loss) available to
common shares..................... $ 5,751 $ 3,986 $ 1,139 $ 4,809 $ 2,663 $ 799 $ (113)
============== ========== ========= ======== ========== ========= =========
Net income (loss) per common share:
Primary........................ $ 0.72 $ 0.63 $ 0.20 $ 0.64 $ 0.45 $ 0.14 $ (0.03)
============== ========== ========= ======== ========== ========= =========
Assuming full dilution......... $ 0.71 $ 0.62 $ 0.20 $ 0.62 $ 0.43 $ 0.14 $ (0.03)
============== ========== ========= ======== ========== ========= =========
Shares used in computing earnings
per common share:
Primary........................ 7,932 6,332 5,755 7,552 5,952 5,755 4,346
============== ========== ========= ======== ========== ========= =========
Assuming full dilution......... 11,030 6,440 5,755 7,735 6,135 5,755 4,346
============== ========== ========= ======== ========== ========= =========
BALANCE SHEET DATA(2):
Working capital..................... $ 10,038 $ 3,626 $ 2,968 N/A $ 4,878 $ 4,712 $ 1,896
Oil and gas properties, net......... 146,088 127,296 68,415 N/A 82,489 57,765 43,920
Total assets........................ 181,554 156,350 99,923 N/A 118,520 83,867 73,786
Total debt.......................... 60,250 60,250 8,950 N/A 24,250 100 19,234
Total stockholders' equity.......... 108,086 82,882 76,268 N/A 77,864 75,129 43,431
OTHER FINANCIAL DATA(2):
Capital expenditures, net........... $ 75,429 $ 56,629 $ 19,874 N/A $ 36,063 $ 24,237 $ 10,412
EBITDA(3)........................... 28,377 21,882 11,534 N/A 16,066 13,582 6,727
Cash provided by operating
activities........................ 26,253 20,308 17,122 N/A 14,323 9,452 5,347
</TABLE>
(FOOTNOTES ON FOLLOWING PAGE)

7
<PAGE>
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(1) Pro forma information gives effect to the Elf Acquisition and the Chevron
Acquisition as if they occurred as of the beginning of the earliest pro
forma period presented. Pro forma, as adjusted information gives effect to
the Elf Acquisition, the Chevron Acquisition and the Offering as if they
occurred on September 30, 1997.

(2) The Company succeeded to the business and properties of Callon Petroleum
Operating Company ("Callon Petroleum Operating"), Callon Consolidated
Partners, L.P. ("CCP") and CN Resources ("CN") on September 16, 1994
(the "Consolidation"). Historical information about the Company prior to
September 16, 1994 includes the financial and operating information of the
predecessors of the Company, other than the interest in CN not owned by
Callon Petroleum Operating, combined as entities under common control in a
manner similar to a pooling of interests. See "The Company."

(3) EBITDA is earnings before interest, taxes, depreciation, depletion and
amortization. EBITDA is a financial measure commonly used in the Company's
industry and should not be considered in isolation or as a substitute for
net income, net cash provided by operating activities or other income or
cash flow data prepared in accordance with generally accepted accounting
principles or as a measure of a company's profitability or liquidity.
Because EBITDA excludes some, but not all, items that affect net income and
may vary among companies, the EBITDA presented above may not be comparable
to similarly titled measures of other companies.

8
<PAGE>
SUMMARY OPERATING AND RESERVE DATA(1)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------------------- ---------------------------------------------
1997 1996 1996 1995 1994
---------------------- --------- ---------------------- --------- ---------
PRO PRO
FORMA(2) HISTORICAL FORMA(2) HISTORICAL
-------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION DATA:
Oil (MBbls)......................... 351 351 451 585 585 594 364
Gas (MMcf).......................... 12,276 9,394 4,784 11,459 6,269 6,694 4,076
Total production (MMcfe)............ 14,379 11,497 7,490 14,970 9,781 10,261 6,260
AVERAGE SALES PRICE:
Oil (per Bbl)....................... $ 18.83 $ 18.83 $ 18.05 $ 18.27 $ 18.27 $ 16.68 $ 15.63
Gas (per Mcf)....................... 2.40 2.45 2.18 2.47 2.40 1.96 2.00
Total production (per Mcfe)......... 2.51 2.57 2.48 2.60 2.63 2.24 2.21
OTHER OPERATING DATA PER MCFE:
Average sales price................. $ 2.51 $ 2.57 $ 2.48 $ 2.60 $ 2.63 $ 2.24 $ 2.21
Lease operating expenses............ 0.36 0.45 0.56 0.41 0.57 0.49 0.49
Severance taxes..................... 0.07 0.09 0.20 0.13 0.20 0.17 0.16
-------- ---------- --------- -------- ---------- --------- ---------
Gross margin........................ $ 2.08 $ 2.03 $ 1.72 $ 2.06 $ 1.86 $ 1.58 $ 1.56
======== ========== ========= ======== ========== ========= =========
<CAPTION>
OCTOBER 31, 1997 DECEMBER 31,
------------------------- --------------------------------
PRO
FORMA(3) HISTORICAL(4) 1996(5) 1995 1994
-------- ------------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C>
RESERVE REPLACEMENT COSTS(6)............ $ 1.07 $ 1.10 $ 0.74 $ 1.05 $ 0.97
ESTIMATED NET PROVED RESERVES:
Oil (MBbls)........................ 3,909 3,909 3,819 4,766 4,424
Gas (MMcf)......................... 94,523 75,912 50,424 29,667 24,102
Gas equivalent (MMcfe)............. 117,977 99,366 73,338 58,263 50,646
PV-10 Value (000s)................. $194,172 $ 158,056 $ 160,171 $ 63,764 $ 41,383
</TABLE>
- ------------

(1) The Company succeeded to the business and properties of its predecessor
entities on September 16, 1994 pursuant to the Consolidation. Historical
data about the Company prior to September 16, 1994 includes the operating
data of the Company's predecessors, other than the interest in CN not owned
by Callon Petroleum Operating, combined as entities under common control in
a manner similar to a pooling of interests. See "The Company."

(2) Pro forma information gives effect to the Elf Acquisition and the Chevron
Acquisition as if they occurred on the date or as of the beginning of the
earliest pro forma period indicated.

(3) Gives effect to the Chevron Acquisition as if it occurred on October 31,
1997.

(4) Future net cash flows attributable to the Company's estimated proved
reserves and the present value of such cash flows were based on an average
gas price of $3.09 per Mcf and an average oil price of $20.09 per Bbl at
October 31, 1997. The average price received for production in the first
nine months of 1997 was $2.41 per Mcf for gas and $18.95 per Bbl for oil,
without the effects of hedging.

(5) Future net cash flows attributable to the Company's estimated proved
reserves and the present value of such cash flows were based on an average
gas price of $3.88 per Mcf and an average oil price of $23.58 per Bbl at
December 31, 1996. The average price received for production in 1996 was
$2.63 per Mcf for gas and $20.55 per Bbl for oil, without the effects of
hedging.

(6) See "Glossary."

<PAGE>
RISK FACTORS

THIS PROSPECTUS INCLUDES "FORWARD-LOOKING STATEMENTS"WITHIN THE MEANING
OF SECTION 27A OF THE SECURITIES ACT AND SECTION 21E OF THE EXCHANGE ACT. ALL
STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED IN THIS
PROSPECTUS, INCLUDING WITHOUT LIMITATION, STATEMENTS UNDER "PROSPECTUS
SUMMARY," "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS" AND "BUSINESS AND PROPERTIES" REGARDING THE COMPANY'S
FINANCIAL POSITION, ESTIMATED RESERVE QUANTITIES AND NET PRESENT VALUES OF
RESERVES, BUSINESS STRATEGY, PLANS AND OBJECTIVES OF MANAGEMENT OF THE COMPANY
FOR FUTURE OPERATIONS AND BUDGET ESTIMATES, ARE FORWARD-LOOKING STATEMENTS.
ALTHOUGH THE COMPANY BELIEVES THAT THE ASSUMPTIONS UPON WHICH SUCH
FORWARD-LOOKING STATEMENTS ARE BASED ARE REASONABLE, IT CAN GIVE NO ASSURANCES
THAT SUCH ASSUMPTIONS WILL PROVE TO HAVE BEEN CORRECT. IMPORTANT FACTORS THAT
COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE COMPANY'S EXPECTATIONS
("CAUTIONARY STATEMENTS") ARE DISCLOSED BELOW AND ELSEWHERE IN THIS
PROSPECTUS. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS
ATTRIBUTABLE TO THE COMPANY OR PERSONS ACTING ON ITS BEHALF ARE EXPRESSLY
QUALIFIED BY THE CAUTIONARY STATEMENTS. PROSPECTIVE INVESTORS SHOULD CAREFULLY
CONSIDER, TOGETHER WITH OTHER INFORMATION IN THIS PROSPECTUS, THE FOLLOWING
FACTORS THAT AFFECT THE COMPANY.

VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION

The Company's revenues, profitability and future growth and the carrying
value of its oil and gas properties are substantially dependent on prevailing
prices of oil and gas. The Company's ability to maintain or increase its
borrowing capacity and to obtain additional capital on attractive terms is also
substantially dependent upon oil and gas prices. Prices for oil and gas are
subject to large fluctuations in response to relatively minor changes in the
supply of and demand for oil and gas, market uncertainty and a variety of
additional factors beyond the control of the Company. These factors include
weather conditions in the United States, the condition of the United States
economy, the actions of the Organization of Petroleum Exporting Countries,
governmental regulation, political stability in the Middle East and elsewhere,
the foreign supply of oil and gas, the price of foreign imports and the
availability of alternate fuel sources. Any substantial and extended decline in
the price of oil or gas would have an adverse effect on the Company's carrying
value of its proved reserves, borrowing capacity, revenues, profitability and
cash flows from operations.

Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploitation
projects.

In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk.

RISKS OF EXPLORATION AND DEVELOPMENT

The major focus of the Company's operations over the next two years is
expected to be the exploration for and development of oil and gas properties,
primarily in federal and state waters in the Gulf of Mexico. Exploration and
drilling activities are generally considered to be of a higher risk than
acquisitions of producing oil and gas properties. Additionally, certain of the
Company's wells seek to discover deposits of gas at deep formations and have
more risk than wells seeking to develop hydrocarbons from shallow formations. No
assurances can be made that the Company will discover oil and gas in commercial
quantities in its exploration and development operations. Expenditure of a
material amount of funds in exploration for oil and gas without discovery of
commercial quantities of reserves will have a material adverse effect upon the
Company.

10
<PAGE>
OPERATING HAZARDS, OFFSHORE OPERATIONS AND UNINSURED RISKS

Callon's operations are subject to risks inherent in the oil and gas
industry, such as blowouts, cratering, explosions, uncontrollable flows of oil,
gas or well fluids, fires, pollution and other environmental risks. These risks
could result in substantial losses to the Company due to injury and loss of
life, severe damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. Moreover, a substantial
portion of the Company's operations are offshore and therefore are subject to a
variety of operating risks peculiar to the marine environment, such as
hurricanes or other adverse weather conditions, to more extensive governmental
regulation, including regulations that may, in certain circumstances, impose
strict liability for pollution damage, and to interruption or termination of
operations by governmental authorities based on environmental or other
considerations.

The Company maintains insurance of various types to cover its operations,
including maritime, employer's liability and comprehensive general liability.
Amounts in excess of base coverages are provided by primary and excess umbrella
liability policies with maximum limits of $50 million. In addition, the Company
maintains operator's extra expense coverage, which provides coverage for the
control of wells drilled and/or producing and redrilling expenses and pollution
coverage for wells out of control.

No assurances can be given that Callon will be able to maintain adequate
insurance in the future at rates the Company considers reasonable. The
occurrence of a significant event not fully insured or indemnified against could
materially and adversely affect the Company's financial condition and results of
operations.

ESTIMATES OF OIL AND GAS RESERVES

This Prospectus contains estimates of oil and gas reserves, and the future
net cash flows attributable to those reserves, prepared by Huddleston & Co.,
Inc., independent petroleum and geological engineers (the "Reserve
Engineers"). There are numerous uncertainties inherent in estimating quantities
of proved reserves and cash flows attributable to such reserves, including
factors beyond the control of the Company and the Reserve Engineers. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact manner. The accuracy of an
estimate of quantities of reserves, or of cash flows attributable to such
reserves, is a function of the available data, assumptions regarding future oil
and gas prices and expenditures for future development and exploitation
activities, and of engineering and geological interpretation and judgment.
Additionally, reserves and future cash flows may be subject to material downward
or upward revisions, based upon production history, development and exploitation
activities and prices of oil and gas. Actual future production, revenue, taxes,
development expenditures, operating expenses, quantities of recoverable reserves
and the value of cash flows from such reserves may vary significantly from the
assumptions and estimates set forth herein. In addition, reserve engineers may
make different estimates of reserves and cash flows based on the same available
data. In calculating reserves on a Mcfe basis, oil was converted to gas
equivalent at the ratio of six Mcf of gas to one Bbl of oil. While this ratio
approximates the energy equivalency of gas to oil on a Btu basis, it may not
represent the relative prices received by the Company on the sale of its oil and
gas production.

The estimated quantities of proved reserves and the discounted present
value of future net cash flows attributable to estimated proved reserves set
forth in this Prospectus were prepared by the Reserve Engineers in accordance
with the rules of the Securities and Exchange Commission (the "Commission"),
and are not intended to represent the fair market value of such reserves.

ABILITY TO REPLACE RESERVES

The Company's future success depends upon its ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable. As is
generally the case in the Gulf Coast region, many of the Company's producing
properties are characterized by a high initial production rate, followed by a
steep decline in production. As a result, the Company must locate and develop or
acquire new oil and gas reserves to replace those being depleted by production.
Without successful exploration or acquisition activities, the

11
<PAGE>
Company's reserves and revenues will decline rapidly. No assurances can be given
that the Company will be able to find and develop or acquire additional reserves
at an acceptable cost.

The exploration for oil and gas requires the expenditure of substantial
amounts of capital, and there can be no assurances that commercial quantities of
oil or gas will be discovered as a result of such activities. The Company's
current capital budget includes drilling 6 gross (2.2 net) development wells and
19 gross (7.5 net) exploratory wells through fiscal 1998. The estimated cost,
net to the Company, to drill and complete these wells is approximately $85.6
million with dry hole costs of approximately $33.4 million. The drilling of
several unsuccessful wells in this area could have a material adverse effect on
the Company. In addition, the successful acquisition of producing properties
requires an assessment of recoverable reserves, future oil and gas prices and
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact and their accuracy inherently
uncertain. In addition, no assurances can be given that the Company's
exploitation and development activities will result in any increases in
reserves. The Company's operations may be curtailed, delayed or canceled as a
result of lack of adequate capital and other factors, such as title problems,
weather, compliance with governmental regulations or price controls, mechanical
difficulties or shortages or delays in the delivery of equipment. In addition,
the costs of exploration and development may materially exceed initial
estimates.

SHORTAGES OF RIGS, EQUIPMENT, SUPPLIES AND PERSONNEL

There is a general shortage of drilling rigs, equipment and supplies which
the Company believes may intensify. The costs and delivery times of rigs,
equipment and supplies are substantially greater than in prior periods and are
currently escalating. Shortages of drilling rigs, equipment or supplies could
delay and adversely affect the Company's exploration and development operations,
which could have a material adverse effect on its financial condition and
results of operations.

The demand for, and wage rates of, qualified rig crews have begun to rise
in the drilling industry in response to the increasing number of active rigs in
service. Such shortages have in the past occurred in the industry in times of
increasing demand for drilling services. If the number of active drilling rigs
continues to increase, the oil and gas industry may experience shortages of
qualified personnel to operate drilling rigs, which could delay the Company's
drilling operations and adversely affect the Company's financial condition and
results of operations.

SUBSTANTIAL CAPITAL REQUIREMENTS

The Company makes, and will continue to make, substantial capital
expenditures for the exploitation, exploration, acquisition and production of
oil and gas reserves. Historically, the Company has financed these expenditures
primarily with cash generated by operations, proceeds from bank borrowings and
issuance of debt and equity securities. The Company's total capital expenditure
budget for drilling and completion costs through fiscal 1998 is approximately
$85.6 million, and could be reduced depending on the success of the Company's
drilling activities. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Capital Expenditures." The Company makes
unsolicited offers for the acquisition of oil and gas properties in the normal
course of business. In the event that any such offers are accepted, the amount
or composition of the Company's capital expenditure budget could be revised
significantly.

If revenues or the Company's borrowing base decrease as a result of lower
oil and gas prices, operating difficulties or declines in reserves, the Company
may have limited ability to expend the capital necessary to undertake or
complete future drilling programs. There can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet these requirements. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

HEDGING OF PRODUCTION

Part of the Company's business strategy is to reduce its exposure to the
volatility of oil and gas prices by hedging a portion of its production. See
"Management's Discussion and Analysis of Financial Condition

12
<PAGE>
and Results of Operations -- Liquidity and Capital Resources." In a typical
hedge transaction, the Company will have the right to receive from the
counterparty 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, the Company is required
to pay the counterparty this difference multiplied by the quantity hedged. The
Company is required to pay the difference between the floating price and the
fixed price (when the floating price exceeds the fixed price) regardless of
whether the Company has 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 the Company to make payments under
the hedge agreements even though such payments are not offset by sales of
production. Hedging will also prevent the Company from receiving the full
advantage of increases in oil or gas prices above the fixed amount specified in
the hedge. Approximately 29% of the Company's estimated oil production for the
last three months of 1997 is hedged at a New York Mercantile Exchange
("NYMEX") floor price of $18.00 per Bbl and a ceiling price of $24.00 per Bbl
(NYMEX). In addition, from October 1997 through March 1998, the Company has
hedged 48% of its estimated natural gas equivalent production at an average
floor price of $2.31 per MMBtu (NYMEX) and an average ceiling price of $3.03 per
MMBtu (NYMEX).

COMPETITION

The Company operates in the highly competitive areas of oil and gas
exploration, development and production. The availability of funds and
information relating to a property, the standards established by the Company for
the minimum projected return on investment, the availability of alternate fuel
sources and the intermediate transportation of gas are factors which affect the
Company's ability to compete in the marketplace. The Company's competitors
include major integrated oil companies, substantial independent energy
companies, affiliates of major interstate and intrastate pipelines and national
and local gas gatherers, many of which possess greater financial and other
resources than the Company. See "Business and Properties -- Competition,
Markets and Regulation."

ENVIRONMENTAL AND OTHER REGULATIONS

The Company's 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 the
acquisition of a permit before drilling commences, restrict the types,
quantities and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas, require remedial measures to mitigate pollution from
former operations, such as plugging abandoned wells, and impose substantial
liabilities for pollution resulting from the Company's operations. Moreover, the
recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. The enactment of stricter legislation or the
adoption of stricter regulations could have a significant impact on the
operating costs of the Company, as well as on the oil and gas industry in
general.

The Company's operations could result in liability for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. Moreover, the Company could be
liable for environmental damages caused by previous property owners. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could have a material adverse effect on the
Company's financial condition and results of operations. The Company maintains
insurance coverage for its operations, including limited coverage for sudden and
accidental environmental damages, but does not believe that insurance coverage
for environmental damages that occur over time is available at a reasonable
cost. Moreover, the Company does 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, the
Company may be subject to liability or may lose the privilege to continue
exploration or production activities upon substantial portions of its properties
in the event of certain environmental damages. See "Business and
Properties -- Environmental Regulations."

13
<PAGE>
The Oil Pollution Act of 1990 imposes a variety of regulations on
"responsible parties" related to the prevention of oil spills. The
implementation of new, or the modification of existing, environmental laws or
regulations, including regulations promulgated pursuant to the Oil Pollution Act
of 1990, could have a material adverse impact on the Company. See "Business and
Properties -- Competition, Markets and Regulation."

CONTROL OF THE COMPANY, STOCKHOLDERS' AGREEMENT

John S. Callon, Fred L. Callon and members of their families (collectively,
the "Callon Family"), NOCO Enterprises, L.P., a limited partnership owned by a
consortium of European institutional investors ("NOCO"), and Fred. Olsen
Energy ASA, a Norwegian public joint-stock company ("F.O. Energy"), who
collectively and beneficially own over 60% of the outstanding Common Stock, are
parties to a stockholders' agreement (the "Stockholders' Agreement") pursuant
to which members of the Callon Family, NOCO and F.O. Energy agree (the Callon
family as one party, and NOCO and F.O. Energy as the other party) (i) to vote
for two directors nominated by each party; (ii) not to support certain changes
in control without the consent of the other party; and (iii) not to sell Common
Stock without first offering it to the other party, except in limited
circumstances. As a result of the Stockholders' Agreement, it is expected that
the members of the Callon Family, NOCO and F.O. Energy will be able to control
the election of at least four directors of the Company. See "Principal
Stockholders -- Stockholders' Agreement."

SHARES ELIGIBLE FOR FUTURE SALE

Each of the Company and its directors and executive officers, the Callon
Family, NOCO and F.O. Energy has agreed not to dispose of any shares of Common
Stock for a period of 90 days from the date of this Prospectus without the
consent of Morgan Keegan & Company, Inc. Following such period and subject to
the volume and other limitations of Rule 144 under the Securities Act, all of
the shares of Common Stock beneficially owned by directors and officers of the
Company will be eligible for public sale. Moreover, the Company may issue shares
of Common Stock in the future. Sales of substantial amounts of Common Stock in
the public market, or the perception of the availability of shares for sale,
could adversely affect the prevailing market price of the Common Stock and could
impair the Company's ability to raise capital through the sale of its
securities.

14
<PAGE>
THE COMPANY

The Company was formed under Delaware law in 1994 to succeed to the
business and properties of Callon Petroleum Operating Company, an independent
energy company owned by members of the Callon Family ("Callon Petroleum
Operating"), Callon Consolidated Partners, L.P., a publicly traded limited
partnership ("CCP"), and CN Resources, a joint venture engaged in the oil and
gas business ("CN").

The predecessors of Callon Petroleum Operating were formed in 1950 by John
S. Callon. Since that time and until September 16, 1994, Callon Petroleum
Operating or its predecessors were actively engaged in the oil and gas business.
CCP was a publicly traded limited partnership formed in 1987 by the
consolidation of oil and gas limited partnerships formed by Callon Petroleum
Operating. Callon Petroleum Operating was the sole general partner of CCP. CN
was a general partnership formed in April 1992 of which Callon Petroleum
Operating and NOCO were the only partners.

Effective September 16, 1994, pursuant to the Consolidation, CCP was merged
into the Company, and the Company acquired all of the capital stock of Callon
Petroleum Operating, as well as the partnership interest in CN formerly owned by
NOCO ("NOCO Interest"). As a result, the Company has acquired the properties
and liabilities of CCP, Callon Petroleum Operating and CN. Because all of the
parties to the Consolidation (other than CN) were under common control, the
financial statements and operating data of the Company include the financial
statements and operating data of CCP and Callon Petroleum Operating, including
Callon Petroleum Operating's ownership interest in CN, which were combined in a
manner similar to a pooling of interests. The acquisition of the NOCO Interest
was recorded as a purchase effective as of the date of the Consolidation
(September 16, 1994). Amounts related to the Company's acquisition of the NOCO
Interest, therefore, are included from the date of the purchase for the periods
presented in the Consolidated Financial Statements.

The Company's principal executive office is located at 200 North Canal
Street, Natchez, Mississippi 39120, and its telephone number is (601) 442-1601.

USE OF PROCEEDS

The net proceeds from this Offering will be $25.2 million ($29.1 million if
the Underwriters' over-allotment option is exercised in full), after deducting
the underwriting discount and estimated offering expenses. The Company intends
to use such net proceeds to pay $18,800,000 of indebtedness incurred to finance
the Chevron Acquisition and to fund a portion of its 1997 and 1998 capital
expenditure budget. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources." Prior
to the utilization of such funds, the Company will invest in short-term
investments. As of November 15, 1997, $18,900,000 was outstanding under the
Credit Facility with a rate of 8.50%.

15
<PAGE>
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock is traded on Nasdaq under the symbol "CLNP." The
following table sets forth the high and low sale prices per share of the Common
Stock as reported on Nasdaq for the periods indicated.

HIGH LOW
---- ----
1995:
1st Quarter........................ $11 $ 9 1/2
2nd Quarter........................ 10 1/2 9
3rd Quarter........................ 12 1/4 9 1/4
4th Quarter........................ 11 9 1/32
1996:
1st Quarter........................ 10 1/2 9 1/2
2nd Quarter........................ 14 1/4 10
3rd Quarter........................ 13 1/2 10 3/4
4th Quarter........................ 19 1/8 12 1/2
1997:
1st Quarter........................ 19 1/2 12 1/2
2nd Quarter........................ 16 3/8 13 1/4
3rd Quarter........................ 19 3/8 15
4th Quarter (through November
24)............................... 22 17 3/4

On November 24, 1997, the last sale price of the Common Stock as reported
on Nasdaq was $18 1/2 per share. On September 30, 1997, there were approximately
7,761 stockholders of record of the Common Stock.

The Company has not paid dividends on the Common Stock and does not intend
to in the near future. The Company intends to reinvest its cash flow into
acquisitions, development and exploration. The Credit Facility prohibits payment
of dividends of the Common Stock.

16
<PAGE>
CAPITALIZATION

The following table sets forth the capitalization of the Company as of
September 30, 1997 and as adjusted to give effect to the Chevron Acquisition and
the sale of the Shares offered by the Company hereby and the application of the
net proceeds as described in "Use of Proceeds." This table should be read in
conjunction with the Company's Consolidated Financial Statements, including the
Notes thereto, and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" found elsewhere in this Prospectus.

SEPTEMBER 30, 1997
----------------------------
PRO FORMA
HISTORICAL AS ADJUSTED(1)
---------- --------------
(IN THOUSANDS)
Cash and cash equivalents............... $ 5,939 $ 12,351
========== ==============
Long-term debt:
Credit Facility.................... $ 100 $ 100
10% Senior Subordinated Notes due
2001.............................. 24,150 24,150
10.125% Senior Subordinated Notes
due 2002(2)....................... 36,000 36,000
Stockholders' Equity:
Preferred Stock, $0.01 par value,
2,500,000 shares authorized;
1,315,500 shares of $2.125
Convertible Exchangeable Preferred
Stock, Series A issued and
outstanding with a liquidation
preference of $32,887,500......... 13 13
Common Stock, $0.01 par value,
20,000,000 shares authorized,
6,028,994 shares outstanding,
7,628,994 as adjusted(3).......... 60 76
Unearned Compensation -- Restricted
Stock(4).......................... (2,410) (2,410)
Capital in excess of par value..... 77,467 102,655
Retained earnings.................. 7,752 7,752
---------- --------------
Total stockholders' equity......... 82,882 108,086
---------- --------------
Total capitalization............... $ 143,132 $168,336
========== ==============

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

(1) Pro forma information gives effect to the Chevron Acquisition as if it
occurred on September 30, 1997.

(2) On July 31, 1997, the Company issued $36.0 million aggregate principal
amount of its 10.125% Series A Senior Subordinated Notes due 2002 ("Series
A Notes") in a private placement. Until November 10, 1997, the Series A
Notes are exchangeable for $36.0 million aggregate principal amount of the
Company's 10.125% Series B Senior Subordinated Notes due 2002 that have been
registered under the Securities Act. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."

(3) Excludes 1,044,000 shares of Common Stock issuable upon exercise of stock
options outstanding as of September 30, 1997, at a weighted average exercise
price of $11.19. Also excludes 2,990,132 shares reserved for issuance
pursuant to the Company's $2.125 Convertible Preferred Stock with a
conversion price of $11 per share. Includes 225,000 performance shares
issued under the Callon Petroleum Company 1996 Stock Incentive Plan which do
not vest until January 1, 2001, and 25,000 restricted shares issued in 1997
under the Callon Petroleum Company 1994 Stock Incentive Plan which vest 20%
annually beginning January 2, 1998.

(4) Represents the unearned portion of restricted stock awards under the
Company's 1996 Stock Incentive Plan. This unearned portion is being
amortized as compensation expense on a straight-line basis over the related
vesting period.

17
<PAGE>
SELECTED FINANCIAL DATA

The following table sets forth, as of the dates and for the periods
indicated, selected financial information for the Company. The financial data
for each of the five years in the period ended December 31, 1996 have been
derived from the audited Consolidated Financial Statements of the Company for
such periods. The financial data for the nine-month periods ended September 30,
1997 and 1996 has been derived from the Company's Unaudited Consolidated
Financial Statements. The data should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements and the Notes thereto. The pro forma
financial information is based upon, and should be read in conjunction with, the
Unaudited Pro Forma Consolidated Financial Statements, including the Notes
thereto, appearing elsewhere in this Prospectus. The following data is not
necessarily indicative of future results for the Company.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------------------------- --------------------------------------------

1997 1996 1996 1995 1994
-------------------------- --------- --------------------- --------- ---------
PRO
FORMA(1) PRO
AS ADJUSTED HISTORICAL FORMA(1) HISTORICAL
----------- ------------ -------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA(2):
Revenues:
Oil and gas sales................... $ 36,058 $ 29,578 $ 18,578 $38,954 $ 25,764 $ 23,210 $ 13,948
Interest and other.................. 1,162 1,162 537 946 946 627 171
----------- ------------ --------- -------- ---------- --------- ---------
Total revenues...................... 37,220 30,740 19,115 39,900 26,710 23,837 14,119
Costs and Expenses:
Lease operating expenses............ 6,219 6,235 5,646 8,102 7,562 6,732 4,042
Depreciation, depletion and
amortization...................... 14,169 11,288 7,697 14,744 9,832 10,376 6,049
General and administrative.......... 3,263 3,263 2,352 3,495 3,495 3,880 3,717
Interest............................ 1,496 945 184 1,861 313 1,794 624
----------- ------------ --------- -------- ---------- --------- ---------
Total costs and expenses....... 25,147 21,731 15,879 28,202 21,202 22,782 14,432
----------- ------------ --------- -------- ---------- --------- ---------
Income (loss) from operations........... 12,073 9,009 3,236 11,698 5,508 1,055 (313)
Provision (benefit) for income
taxes................................. 4,225 2,926 -- 4,094 50 -- (200)
----------- ------------ --------- -------- ---------- --------- ---------
Income (loss) before cumulative effect
of change in accounting principle..... 7,848 6,083 3,236 7,604 5,458 1,055 (113)
Cumulative effect of change in
accounting principle.................. -- -- -- -- -- -- --
----------- ------------ --------- -------- ---------- --------- ---------
Net income (loss)....................... 7,848 6,083 3,236 7,604 5,458 1,055 (113)
Preferred stock dividends............... 2,097 2,097 2,097 2,795 2,795 256 --
----------- ------------ --------- -------- ---------- --------- ---------
Net income (loss) available to common
shares................................ 5,751 3,986 1,139 4,809 2,663 799 (113)
----------- ------------ --------- -------- ---------- --------- ---------
Pro forma adjustment (unaudited):
Provision for income taxes.......... -- -- -- -- -- -- --
----------- ------------ --------- -------- ---------- --------- ---------
Pro forma net income (loss)............. $ 5,751 $ 3,986 $ 1,139 $ 4,809 $ 2,663 $ 799 $ (113)
=========== ============ ========= ======== ========== ========= =========
Net income (loss) per common share:
Primary............................. $ 0.72 $ 0.63 $ 0.20 $ 0.64 $ 0.45 $ 0.14 $ (0.03)
=========== ============ ========= ======== ========== ========= =========
Assuming full dilution.............. $ 0.71 $ 0.62 $ 0.20 $ 0.62 $ 0.43 $ 0.14 $ (0.03)
=========== ============ ========= ======== ========== ========= =========
Shares used in computing earnings per
common share:
Primary............................. 7,932 6,332 5,755 7,552 5,952 5,755 4,346
=========== ============ ========= ======== ========== ========= =========
Assuming full dilution.............. 11,030 6,440 5,755 7,735 6,135 5,755 4,346
=========== ============ ========= ======== ========== ========= =========
</TABLE>
1993 1992
--------- ---------

STATEMENT OF OPERATIONS DATA(2):
Revenues:
Oil and gas sales................... $ 10,048 $ 10,015
Interest and other.................. 230 232
--------- ---------
Total revenues...................... 10,278 10,247
Costs and Expenses:
Lease operating expenses............ 3,713 3,702
Depreciation, depletion and
amortization...................... 3,411 3,360
General and administrative.......... 2,350 1,848
Interest............................ 196 160
--------- ---------
Total costs and expenses....... 9,670 9,070
--------- ---------
Income (loss) from operations........... 608 1,177
Provision (benefit) for income
taxes................................. 113 235
--------- ---------
Income (loss) before cumulative effect
of change in accounting principle..... 495 942
Cumulative effect of change in
accounting principle.................. 5,262 --
--------- ---------
Net income (loss)....................... 5,757 942
Preferred stock dividends............... -- --
--------- ---------
Net income (loss) available to common
shares................................ 5,757 942
--------- ---------
Pro forma adjustment (unaudited):
Provision for income taxes.......... 100 145
--------- ---------
Pro forma net income (loss)............. $ 5,657 $ 797
========= =========
Net income (loss) per common share:
Primary............................. $ 1.53 $ 0.25
========= =========
Assuming full dilution.............. $ 1.53 $ 0.25
========= =========
Shares used in computing earnings per
common share:
Primary............................. 3,769 3,769
========= =========
Assuming full dilution.............. 3,769 3,769
========= =========

(TABLE CONTINUED ON FOLLOWING PAGE)

18
<PAGE>
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------------------------- --------------------------------------------

BALANCE SHEET DATA(2):
Working capital..................... $ (687) $ (1,011)
Oil and gas properties, net......... 21,000 22,138
Total assets........................ 39,825 35,570
Total debt.......................... 2,691 2,975
Total stockholders' equity.......... 27,170 22,711
OTHER FINANCIAL DATA(2):
Capital expenditures, net........... $ 2,710 $ 3,817
EBITDA(3)........................... 4,496 4,949
Cash provided by operating
activities........................ 4,735 2,031

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

(2) The Company succeeded to the business and properties of Callon Petroleum
Operating, CCP and CN on September 16, 1994 pursuant to the Consolidation.
Historical information about the Company prior to September 16, 1994
includes the financial and operating information of the predecessors of the
Company, other than the interest in CN not owned by Callon Petroleum
Operating, combined as entities under common control in a manner similar to
a pooling of interests. See "The Company."

<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

GENERAL

The Company uses the full cost method of accounting for the Company's
investment in oil and gas properties. Under the full cost method of accounting,
all costs of acquisition, exploration and development of oil and gas reserves
are capitalized into a "full cost pool." Oil and gas properties in the pool,
plus estimated future expenditures to develop proved reserves and future
abandonment, site remediation and dismantlement costs, are depreciated, depleted
and amortized by a charge to operations using the unit of production method
based on the ratio of current production to total estimated proved recoverable
oil and gas reserves. To the extent that such capitalized costs (net of
depreciation, depletion and amortization) exceed the discounted future net cash
flows on an after-tax basis of estimated proved oil and gas reserves, such
excess costs are charged to operations. Once incurred, the write-down of oil and
gas properties is not reversible at a later date even if oil or natural gas
prices increase. The Company has not had a ceiling test write-down since 1986.

RESULTS OF OPERATIONS

The following table sets forth selected operating data for the Company for
the periods and upon the basis indicated.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- -------------------------------
1997 1996 1996 1995 1994
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Production:
Oil (MBbls)..................... 351 451 585 594 364
Gas (MMcf)...................... 9,394 4,784 6,269 6,694 4,076
Total production (MMcfe)........ 11,497 7,490 9,781 10,261 6,260
Average Sales Price:
Oil (per Bbl)................... $ 18.83 $ 18.05 $ 18.27 $ 16.68 $ 15.63
Gas (per Mcf)................... 2.45 2.18 2.40 1.96 2.00
Total production (per Mcfe)..... 2.57 2.48 2.63 2.24 2.21
Average Costs (per Mcfe):
Lease operating expenses
(excluding severance taxes)... $ 0.45 $ 0.56 $ 0.57 $ 0.49 $ 0.49
Severance taxes................. 0.09 0.20 0.20 0.17 0.16
Depreciation, depletion and
amortization.................. 0.98 1.03 1.01 1.01 0.97
General and administrative (net
of management fees)........... 0.28 0.31 0.36 0.38 0.59
</TABLE>
The following table sets forth selected production data for the Company for
the periods and upon the basis indicated.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- -------------------------------
1997 1996 1996 1995 1994
--------- --------- --------- --------- ---------
(MMCFE) (MMCFE)
<S> <C> <C> <C> <C> <C>
Production attributable to:
Main Pass 163 Area.............. 3,333 122 463 -- --
Chandeleur Block 40............. 3,094 1,158 1,385 144 37
Big Escambia Creek.............. 650 578 739 390 --
Black Bay Complex............... 803 914 1,208 1,351 603
North Dauphin Island Field...... 1,132 2,514 3,069 5,102 2,524
--------- --------- --------- --------- ---------
9,012 5,286 6,864 6,987 3,164
Other properties................ 2,485 2,204 2,917 3,274 3,096
--------- --------- --------- --------- ---------
Total...................... 11,497 7,490 9,781 10,261 6,260
========= ========= ========= ========= =========
</TABLE>
20
<PAGE>
NINE MONTHS ENDED SEPTEMBER 30, 1997 COMPARED WITH THE NINE MONTHS ENDED
SEPTEMBER 30, 1996

For the nine months ended September 30, 1997, total oil and gas revenues
increased by $11 million, or 59%, to $29.6 million compared to $18.6 million for
the same period in 1996.

For the nine months ended September 30, 1997, oil production and revenues
decreased to 351 MBbls and $6.6 million, respectively. For the comparable period
in 1996, oil production was 451 MBbls while revenues totaled $8.1 million. Oil
prices during the first nine months of 1997 averaged $18.83, compared to $18.05
for the same period in 1996. Although prices were higher, the loss of production
from the properties which were sold and the decline in other non-core properties
caused the overall decline in oil revenues.

Natural gas production and revenues for the nine-month period ended
September 30, 1997 were 9.39 Bcf and $23 million, respectively, increasing from
4.78 Bcf and gas revenues of $10.4 million in the first nine months of 1996. The
average sales price for natural gas in the first nine months of 1997 was $2.45
per Mcf, a $0.27 per Mcf increase over the same period in 1996. The combination
of increased prices and production volumes generated the 120% increase in total
gas revenues.

Lease operating expenses, excluding severance taxes, for the first nine
months of 1997 increased by 24% to $5.2 million from $4.2 million for the
comparable period in 1996. This increase is primarily the result of expenses
associated with new producing properties. Severance taxes decreased by 29% to
$1.1 million during the first nine months of 1997 from $1.5 million for the same
period in 1996 as a result of production declines in the Company's onshore
properties and property sales and a higher portion of the Company's production
coming from federal offshore leases, which are not subject to severance taxes.

Depreciation, depletion and amortization for the first nine months of 1997
was $11.3 million, or $0.98 per Mcfe. For the same period in 1996, the total was
$7.7 million and $1.03 per Mcfe.

During the first nine months of 1997, general and administrative expenses
increased by 39% to $3.3 million compared to $2.4 million for the nine-month
period ended September 30, 1996. Increased compensation expense related to stock
plans and a reduction in management fees as a result of property sales, combined
to produce this overall increase.

Interest expense during the first three quarters of 1997 was $945,000
compared to $184,000 for the first three quarters of 1996 as a result of the
increase in the Company's long-term debt.

YEAR ENDED DECEMBER 31, 1996 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1995

Oil and gas sales increased $2.6 million, or 11%, during 1996 to $25.8
million compared to $23.2 million in 1995. While oil and gas production volumes
for 1996 were lower than those reported in 1995, substantial price increases for
both oil and gas more than offset the loss in revenues. The average sales price
per Bbl sold in 1996 increased to $18.27, compared to $16.68 for 1995. The
average sales price per Mcf of gas sold increased from $1.96 in 1995 to $2.40 in
1996.

Oil production for 1996 decreased slightly to 585 MBbls from the 594 MBbls
produced in 1995. This reduction was primarily attributable to the
implementation of the required environmental protection program (zero discharge)
at the Black Bay Complex, the Company's largest single oil producing prospect.
During this process, several producing wells were shut-in while various new
equipment was installed. In addition, several wells were temporarily shut-in
while repairs were conducted on the service lines. Therefore, average daily
production for 1996 dropped to 1,599 Bbls/d compared to 1,629 Bbls/d in 1995.

Gas production for 1996 was 6.3 Bcf, a decrease from the 6.7 Bcf reported
in 1995. This reduction was primarily attributable to the loss of production
from the North Dauphin Island Field where problems with excess water content in
the gas sales stream were encountered early in the year requiring the
installation of a dehydrator and removal of water from the lines. Extraneous
water production from the #2A well led to the shut-in of the well and the
natural decline of the reservoir pressure. Also during the year, this field
incurred a lower production rate due to compressor inefficiencies which led to a
compressor restaging program that was completed in late September.

21
<PAGE>
Lease operating expenses, including severance taxes, increased from $6.7
million in 1995 to $7.6 million in 1996. A large portion of this increase,
$600,000, was attributable to normal expenses associated with new property
additions. Other expenses included the installation of a dehydrator and the
workover expenses at the North Dauphin Island Field.

Depreciation, depletion and amortization expense for 1996 was $9.8 million
compared to $10.4 million for 1995. When compared on a per unit-of-production
basis, the expense incurred was $1.01 per Mcfe produced for each of the two
years.

General and administrative expenses declined from $3.9 million for 1995 to
$3.5 million for 1996, as a result of the Company's continued efforts to improve
operational efficiencies.

Interest expense decreased from $1.8 million in 1995 to $313,000 in 1996.
This expense reduction corresponds with the smaller average monthly outstanding
balance on the long-term debt of the Company for 1996 when compared to 1995.
During the fourth quarter of 1995, the Company used $21.5 million of the
proceeds from the sale of preferred stock to reduce its long-term debt. During
the course of 1996, additional funds advanced under the Company's line of credit
were repaid in November with the proceeds from the issuance of $24.2 million of
the Company's 10% Senior Subordinated Notes due 2001 (the "10% Notes"). The
average outstanding balance in long-term debt during 1996 was $5.3 million.

The recorded income tax expense for 1996 was $50,000. The computed
provision for income taxes at the Company's expected statutory rate was $1.9
million, which was primarily offset by a reduction in the deferred tax asset
valuation allowance as a result of the Company's ability to utilize its net
operating losses and depletion carryovers.

YEAR ENDED DECEMBER 31, 1995 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1994

Oil and gas sales increased $9.3 million, or 66%, during 1995 to $23.2
million compared with $13.9 million in 1994. This increase was partially
attributable to the Company's purchase in September 1994 of NOCO's interest in
CN pursuant to the Consolidation as well as the acquisition of certain
properties from W&T Offshore, Inc. ("1994 Properties"). The Company's purchase
of the Escambia Minerals properties in June 1995 also contributed $1.9 million
to the increase in oil and gas sales.

Oil production attributable to the NOCO Interest, the Escambia Minerals
properties and the 1994 Properties substantially outweighed normal production
declines in previously existing properties, as oil production for 1995 increased
to 594 MBbls from the 1994 level of 364 MBbls. The average price per Bbl sold
also increased by $1.05 in 1995 from 1994 prices, resulting in a total $4.3
million increase in oil revenues.

Total gas production increased 2.6 Bcf to 6.7 Bcf in 1995 from 4.1 Bcf in
1994. A substantial portion of this increase in production was attributable to
the Company's acquisition of the North Dauphin Island Field. Gas production from
the North Dauphin Island Field increased from 2.5 Bcf in 1994 to 5.1 Bcf in 1995
and added $5.0 million in revenues in 1995 compared with 1994. Although spot
market gas prices declined in 1995, gas price hedges limited the effect of the
decline to $0.04 per Mcf.

Lease operating expenses, including production taxes, increased 67% during
1995 to $6.7 million, compared to $4.0 million for 1994. This increase was
largely attributable to the corresponding increase in oil and gas production
caused by the Company's acquisition of the NOCO Interest, the Escambia Minerals
properties and the 1994 Properties. The Company's purchase of the NOCO Interest
in September 1994 resulted in an increase in combined lease operating expenses
attributable to the North Dauphin Island Field and the Black Bay Complex from
$1.5 million in 1994 to $3.6 million in 1995. Lease operating expenses on an
Mcfe basis increased by less than 2% to $0.66 for 1995 compared to $0.65 for
1994.

Total depreciation, depletion and amortization expense was $10.4 million
for 1995, compared to $6.0 million for 1994. This increase reflects additional
production and reserves resulting from the purchase of the NOCO Interest, the
Escambia Minerals properties and the 1994 Properties.

General and administrative expenses were $3.9 million for 1995, compared to
$3.7 million in 1994. The increase was primarily attributable to the Company's
expanding operations.

22
<PAGE>
The Company had a zero effective tax rate for 1995, compared to an
effective rate of (63)% in 1994. The 1995 rate was primarily due to a reduction
in the deferred tax asset valuation allowance of $551,000. The valuation
allowance was reduced during 1995 due to a reduction in the gross deferred tax
asset. This valuation allowance represents the portion of federal net operating
loss carry forward and other temporary differences which the Company believes
will not be utilized.

LIQUIDITY AND CAPITAL RESOURCES

CAPITAL SOURCES

The Company's primary sources of capital are its cash flows from
operations, borrowings from financial institutions and the sale of debt and
equity securities. Cash provided from operations during 1996 totaled $14.3
million. During 1996, the Company borrowed $12.9 million from financial
institutions and repaid such borrowing with the proceeds from the sale of $24.2
million of its 10% Notes completed in November 1996. At December 31, 1996, the
Company had working capital in the amount of $4.9 million. Net cash provided by
operating activities for the nine months ended September 30, 1997 totaled $20.3
million. During the first nine months of 1997, a total of $61 million was paid
for capital expenditures, $18.5 million for debt repayments and $2.1 million was
paid as dividends to the preferred stockholders.

Effective October 31, 1996, the Company entered into a new Credit Facility
with Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. The Credit Facility provides for borrowings of a maximum of the
lesser of $50 million or a borrowing base ("Borrowing Base") of $30 million
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 either the
lender's prime rate or the lender's prime rate plus 0.50%. The Company, at its
option, may fix the interest rate on all or a portion of the outstanding
principal balance at either 1.00% or 1.375% above a defined "Eurodollar" rate,
depending upon the percentage of the unused portion of the Borrowing Base, for
periods of up to six months. The weighted average interest rate for the total
debt outstanding at December 31, 1996 was 8.25%. 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. At September 30, 1997, the unpaid balance due
on the Credit Facility was $100,000.

On November 27, 1996, the Company issued $24.2 million of its 10% Notes.
The Company used the proceeds to pay down the Credit Facility and for other
corporate purposes. Interest on the 10% Notes is payable quarterly and began on
March 15, 1997. The 10% 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 10% Notes are general
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
10.125% Senior Subordinated Notes due 2002. The Credit Facility and the
indenture for the 10% Notes contain various covenants including restrictions on
additional indebtedness and payment of cash dividends as well as maintenance of
certain financial ratios.

On July 31, 1997, the Company issued $36 million of its 10.125% Series A
Senior Subordinated Notes due 2002 in a private placement for net proceeds of
$34.8 million. The Company used $18.5 million of the net proceeds to repay
borrowings under the Credit Facility and the remaining net proceeds have been
allocated to the Company's capital expenditure budget. On September 10, 1997,
pursuant to a Registration Agreement dated July 31, 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 form and terms
of the Series A Notes, except for certain transfer restrictions and provisions
relating to registration rights. The exchange offer was completed on

23
<PAGE>
November 10, 1997 and $36 million principal amount of Series A Notes were
exchanged for $36 million principal amount of Series B Notes. 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 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 indenture for the
10.125% Notes contain various covenants including restrictions on additional
indebtedness and payment of cash dividends as well as maintenance of certain
financial ratios.

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 is sold. From October 1, 1996 to
March 31, 1997, the Company had in effect hedges of gas equivalent to
approximately 16% of its production at a floor price per MMBtu of $1.75 (NYMEX)
and a ceiling price per MMBtu of $2.20 (NYMEX). In addition, the Company was
party to hedges in effect from October 1, 1996 through December 31, 1996
representing approximately 81% of its oil production at a floor price per Bbl of
$17.25 (NYMEX) and a ceiling price per Bbl of $19.59 (NYMEX). During the third
quarter of 1996, the Company terminated hedges attributable to its fourth
quarter 1996 production at a profit, which had the effect of increasing fourth
quarter oil and gas revenues by $180,000. The Company is currently a party to
hedges that will be in effect for the last three months of 1997 representing
approximately 29% of its estimated oil production, at a floor price of $18.00
per Bbl (NYMEX) and a ceiling price per Bbl of $24.00 (NYMEX). In addition, from
October 1997 through March 1998, the Company has open hedging positions covering
48% of its estimated natural gas equivalent production at an average floor price
of $2.31 per MMBtu (NYMEX) and an average ceiling price of $3.03 per MMBtu
(NYMEX). In addition, the Company has realized gains of $290,000 from
termination of swap contracts relating to December 1997 and January 1998 natural
gas production.

CAPITAL EXPENDITURES

Capital expenditures for 1996 totaled $36.1 million which included $19.2
million of lease acquisitions, $2.7 million for the acquisition of producing
properties and equipment and $14.2 million for property development and drilling
activities on its properties. During the first nine months of 1997, capital
expenditures were $61 million. Of such amount, approximately $24 million was
expended on drilling, development and exploration activities and $37 million on
acquisitions of producing properties, undeveloped mineral interests and seismic
information attributable to future drilling sites.

The Company focuses on exploration and development drilling. The Company's
capital budget through fiscal 1998 contemplates the drilling of 6 gross (2.2
net) development wells and 19 gross (7.5 net) exploratory wells, at an estimated
net cost to the Company to drill and complete of $85.6 million. These drilling
operations will be financed through cash flows from operations, the net proceeds
of this Offering, and borrowings under the Company's Credit Facility. The
Company had available borrowings under its Credit Facility of $40 million as of
September 30, 1997. See "Use of Proceeds." If the Company's initial drilling
operations are not successful, the Company may redeploy its remaining capital
budget to other activities. See "Risk Factors -- Substantial Capital
Requirements."

ACCOUNTING POLICIES

In February 1997, the Financial Accounting Standards Board issued Statement
No. 128 ("FAS 128"), "Earnings Per Share," which simplifies the computation
of earnings per share. FAS 128 is effective for financial statements issued for
periods ending after December 15, 1997 and requires restatement for all prior
period earnings per share data presented. The Company intends to comply with FAS
128.

Also in early 1997, the Financial Accounting Standards Board issued
Statement No. 129 ("FAS 129"), "Disclosure of Information about Capital
Structure" effective for financial statements

24
<PAGE>
issued for periods ending after December 15, 1997. The Company believes it is in
compliance with the provisions of this statement.

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 is effective for
fiscal years beginning after December 15, 1997. The Company intends to comply
with the provisions of FAS 130.

Also in mid-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 the way that public businesses
report information about operating segments in annual financial statements and
requires those enterprises report selected information about operating segments
in interim financial reports issued to shareholders. FAS 131 is effective for
fiscal years beginning after December 15, 1997. The Company intends to comply
with the provisions of FAS 131.

25
<PAGE>
BUSINESS AND PROPERTIES

THE COMPANY

Callon Petroleum Company has been engaged in the acquisition, development,
exploration and production of oil and gas since 1950. The Company's properties
are geographically concentrated offshore in the Gulf of Mexico and onshore in
Louisiana and Alabama. As of October 31, 1997, on a pro forma basis, the Company
had estimated net proved reserves of 118 Bcfe with a PV-10 Value of $194.2
million, representing increases of 61% and 21%, respectively, from December 31,
1996. Approximately 93% of these pro forma reserves are proved developed.
Average daily production during the first nine months of 1997 was 42.1 MMcfe/d,
representing an increase of 54% over the first nine months of 1996.

o Increased pro forma estimated net proved reserves to 118 Bcfe from
50.6 Bcfe at a Reserve Replacement Cost of $1.07 per Mcfe.

o Increased the pro forma PV-10 Value of estimated net proved
reserves to $194.2 million from $41.4 million.

o Completed 14 acquisitions of properties with estimated net proved
reserves of 80.4 Bcfe for a total acquisition cost of $68.4
million, or $0.85 per Mcfe, on a pro forma basis.

o Spent $14.2 million to drill and complete 3 exploratory wells and
12 development wells, which added estimated net proved reserves of
27.8 Bcf.

o Assembled an inventory of 37 exploration prospects in the Gulf of
Mexico which remain to be drilled.

o Increased EBITDA to $16.1 million in 1996 from $6.7 million in
1994. For the first nine months of 1997, EBITDA rose 90% to $21.9
million compared with the first nine months of 1996.

BUSINESS STRATEGY

EXPLORATION AND DEVELOPMENT ACTIVITIES

26
<PAGE>
shallow gas deposits. These seismic techniques utilize high-definition two
dimensional seismic lines shot in a tight grid, with spacing as close as 50
meters. The Company has developed a proprietary method of processing and
interpreting this data which the Company believes gives it a competitive
advantage over other companies exploring in the Shallow Miocene Trend. During
1996, the Company completed four proprietary high-resolution seismic surveys
over an eight block area contiguous to Chandeleur Block 40. Based on these
surveys, between October 1996 and July 1997, the Company drilled 2 gross (1.5
net) successful development wells, 2 gross (2.0 net) successful exploratory
wells and one unsuccessful (0.7 net) development well in this area for a
drilling success rate of 80%. Primarily as a result of these wells, the
Company's average daily production for the first nine months of 1997 increased
to 42.1 MMcfe/d, a 54% increase over the same period of 1996. The Company
intends to use this high-resolution seismic technique to confirm 3-D seismic
surveys of shallow gas prospects on its Brazos Blocks 582 and 610 in the Gulf of
Mexico. Through year end 1998, the Company's budget includes drilling 3 gross
(2.4 net) exploration wells and 2 gross (1.2 net) development wells in the
Shallow Miocene Trend and Brazos Blocks 582 and 610, for a total net dry hole
cost of $10.9 million, excluding completion and development costs.

The Company and Murphy have also acquired acreage and generated five
prospects in the deep waters of the Gulf of Mexico. The Company plans to drill
an exploration well with Murphy in 900 feet of water during the fourth quarter
of 1997. Estimated dry hole costs to drill this well are $2.2 million, net to
Callon.

In total, the Company's current capital budget through fiscal 1998 of $85.6
million contemplates the drilling of 6 gross (2.2 net) development wells and 19
gross (7.5 net) exploratory wells, at an estimated net dry hole cost to the
Company of $33.4 million and $52.2 million in completion and development costs.
These drilling operations will be financed through cash flows from operations,
the net proceeds of this Offering, the proceeds of property sales and borrowings
under the Company's Credit Facility. The Company's Credit Facility had an
available borrowing base of $40 million as of September 30, 1997. See "Use of
Proceeds."

27
<PAGE>
RECENT DEVELOPMENTS

RECENT ACQUISITIONS. In June 1997, the Company closed an $11.8 million
acquisition from Elf Exploration, Inc. for their interest in three adjoining
blocks located in the Shallow Miocene Trend in federal waters in the Mobile
Block 864 Area. In August 1997, for $7.5 million Callon acquired from Koch
Exploration Company an interest in two wells producing from the Shallow Miocene
Trend adjoining the blocks acquired in the Elf Acquisition. Additionally, in
September 1997, at a purchase price of $10.6 million the Company acquired from
Santa Fe Energy Resources, Inc. additional interests in the properties acquired
in the Koch Acquisition, along with an interest in a well in a nearby block. In
total, the Company spent $29.9 million to acquire properties in the Mobile Block
864 Area which as of October 31, 1997, had estimated net proved reserves of 32
Bcfe. The Company's average net daily production during September 1997 from this
area was 6.9 MMcf/d.

In October 1997, the Company agreed to purchase 61% of Chevron U.S.A.
Inc.'s interest in the Mobile Block 864 Area for $21 million, effective July 1,
1997. As of October 31, 1997, estimated net proved reserves attributable to the
Chevron Acquisition were 18.6 Bcfe. The Chevron Acquisition closed on November
7, 1997 for a net acquisition cost of $18.8 million. As a result of this
acquisition, the Company will have acquired an average 55.4% working interest in
seven blocks, a 53.3% working interest in the Mobile Block 864 Area unit and the
unit production facilities, a 66.7% working interest in two producing wells and
a 50% working interest in another well. The Company became the operator of the
unit representing approximately 57% of its estimated net proved reserves in the
Mobile Block 864 Area as of October 31, 1997 on an Mcfe basis, and related
production facilities.

28
<PAGE>
SIGNIFICANT PRODUCING PROPERTIES

The following table shows the PV-10 Value and estimated net proved oil and
gas reserves by major field for the Company's five largest producing fields and
for all other properties combined at October 31, 1997 on a pro forma basis
giving effect to the Chevron Acquisition.
<TABLE>
<CAPTION>
ESTIMATED NET PROVED
---------------------------------------------
PERCENT
PV-10 TOTAL OIL GAS TOTAL
PRIMARY VALUE PV-10 RESERVES RESERVES RESERVES
FIELD NAME/LOCATION OPERATOR(S) ($000)(1) VALUE (MBBLS) (MMCF) (MMCFE)
- ------------------------------------- ----------- ---------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Mobile Block 864 Area................ Various(2) $ 91,230 46.98% -- 50,620 50,620
Federal Waters
Chandeleur Block 40.................. Callon 26,321 13.56% -- 12,518 12,518
Federal Waters
Main Pass 32/35 Area................. Callon 17,818 9.18% 262 6,084 7,656
Louisiana State Waters
Main Pass 163 Area................... Callon 15,723 8.10% -- 11,028 11,028
Federal Waters
Big Escambia Creek................... Exxon USA 11,747 6.05% 961 2,425 8,191
Southeast Alabama
Other properties..................... Various 31,333 16.13% 2,686 11,848 27,964
---------- --------- -------- -------- --------
Total........................... $ 194,172 100.00% 3,909 94,523 117,977
========== ========= ======== ======== ========
</TABLE>
- ------------

(1) Future net cash flows attributable to the Company's estimated proved
reserves and the present value of such cash flows were based on an average
gas price of $3.09 per Mcf and an average oil price of $20.09 per Bbl at
October 31, 1997. The average price received for production in the first
nine months of 1997 was $2.41 per Mcf for gas and $18.95 per Bbl for oil,
without the effects of hedging.

(2) Following the Chevron Acquisition, the Company became operator of five wells
in the Mobile Block 864 Area, representing 57% of the Company's estimated
net proved reserves on an Mcfe basis as of October 31, 1997.

MOBILE BLOCK 864 AREA

The Mobile Block 864 area is located offshore Alabama in the federal waters
of the OCS. During the first nine months of 1997, the Company consummated three
acquisitions in this area and, in October 1997, agreed to acquire additional
interests in producing properties from Chevron. In total, the Company has
acquired an average 55.4% working interest in seven blocks, a 53.3% working
interest in the Mobile Block 864 Area unit and the unit production facilities, a
66.7% working interest in two producing wells and a 50% working interest in
another well. During September 1997, the unit and three wells averaged gross
daily production of 36.1 MMcf from reservoirs in the Shallow Miocene Trend at
depths ranging from 2,400 to 2,700 feet. Pro forma for the Chevron Acquisition,
the Mobile Block 864 Area had estimated net proved reserves at October 31, 1997
of 50.6 Bcf and a PV-10 value of $91.2 million. Net average daily production
during September 1997, on a pro forma basis giving effect to the Chevron
Acquisition, was 16.5 MMcf.

Following the acquisition from Chevron, the Company was appointed operator
of the Mobile Block 864 Area unit. Production from three wells in the area is
currently constrained by the capacity of the unit production facilities. The
Company plans to add compression facilities to the existing platform to increase
productive capacity during 1998. The Company has also identified two development
prospects and one exploration prospect in this area using available 3-D seismic.
Following the acquisition from Chevron, the Company plans to conduct an
extensive shallow focus, high-resolution seismic survey over the area to refine
its development plans and to explore for additional prospects during 1998.

CHANDELEUR BLOCK 40

The Company and an institutional investor purchased a 33.3% working (27.8%
net revenue) interest in Chandeleur Block 40 in 1994 located in the Shallow
Miocene Trend. On December 29, 1995, Callon

29
<PAGE>
acquired an additional 66.7% working (55.5% net revenue) interest in the
Chandeleur Block 40 for $9 million and subsequently sold a 22.2% working
interest in the field to an industry partner for $3 million. The Company
currently holds a combined 52.3% working (43.6% net revenue) interest in this
property. The field's remaining proved reserves are estimated to be 12.5 Bcf of
natural gas (net to the Company) as of October 31, 1997.

When the Company assumed operations of the field, two wells were producing
5.5 MMcf/d of natural gas from the 3,800 foot sand. In February 1996, the
Company shut-in one well and successfully reworked the other and increased
average field production to 10.5 MMcf/d of natural gas.

During the fourth quarter of 1996, the Company drilled a development well
in the field. For the nine months ended September 30, 1997, the well was
producing an average of 19.7 MMcf/d. The well resulted in a field extension
which added 6 Bcf in estimated net proved reserves to the Company as of December
31, 1996. Total field production averaged approximately 26.0 MMcf/d during the
first nine months of 1997.

MAIN PASS 32/35 AREA

In the Main Pass 32/35 Area, the Company owns and operates 14 producing
wells in a field located in shallow Louisiana-state waters which produces oil
and gas from reservoirs at depths of between 6,000 and 9,000 feet. In November
1996, the Company completed a 36 square-mile seismic survey covering its Main
Pass Block 35 field and adjoining acreage. Based upon this data, the Company
negotiated two separate farm-in agreements for a 100% working interest covering
a prospect with reserve potential updip from existing production in a Cib Carst
reservoir on Main Pass Block 31. In August 1997, the SL 12002 #1 was drilled to
a total vertical depth of 10,900 feet, completed in a laminated pay section
between 10,590 and 10,602 feet and tested at rates up to 7.5 MMcf/d with 334
barrels of condensate. The main pay section lies between 10,536 and 10,566 feet
and has not been tested. The Company expects to place the SL 12002 #1 on
production in December 1997 after flowlines are laid to a Company-operated
production facility at Main Pass Block 32. The SL 12002 #1 had proved reserves
at October 31, 1997 of 7.7 Bcfe and a PV-10 value of $17.8 million.

MAIN PASS 163 AREA

In two separate transactions during 1996, Callon acquired a 100% working
interest in Chandeleur Block 41 and Main Pass Blocks 159, 160, 161 and 163
located in the Shallow Miocene Trend. The acquisition initially included five
wells producing 4 MMcf/d, as well as production facilities at Main Pass 163
capable of handling 90 MMcf/d.

Based upon interpretation of seismic data acquired and processed by Callon,
an exploratory well was drilled on Main Pass Block 163 during the fourth quarter
of 1996. For the nine months ending September 30, 1997, the well produced an
average of 10.5 MMcf/d. A development well was also drilled during the fourth
quarter of 1996 on Main Pass Block 161 and produced an average of 1.3 MMcf/d
during the first nine months of 1997. During the second quarter of 1997, the
Company drilled a successful well on Chandeleur Block 41 and production
commenced in July 1997. Total production from the Main Pass 163 Area averaged
approximately 15.5 MMcf/d for the first nine months of 1997.

The Main Pass 163 Area wells produce from Shallow Miocene reservoirs at
approximate depths of 3,300 feet. Proved reserves at October 31, 1997
attributable to this area were 11.0 Bcf, representing 7.25% of the Company's
total PV-10 Value.

BIG ESCAMBIA CREEK

On June 29, 1995, the Company purchased an average working interest of 6.0%
(6.6% net revenue interest), subject to a 10% reduction after payout, in nine
wells and a 2.9% average royalty interest in another six wells. The gross
average daily production for these wells during August 1997 was 3 MBbls of
condensate, 1.7 MBbls of natural gas liquids, 9.1 MMcf of residue natural gas
and 391 long tons of sulphur. These wells are producing from the Smackover
formation at depths ranging from 15,100 to 15,600 feet. Production in this field
has been partially curtailed due to low treatment plant capacity and, as a
result, no significant field production decline occurred during the past several
years.

30
<PAGE>
RESERVES

The following table sets forth certain information about the estimated net
proved reserves of the Company as of the dates set forth below.
<TABLE>
<CAPTION>
OCTOBER 31, 1997 DECEMBER 31,
---------------------------- --------------------------------
PRO FORMA(1) HISTORICAL(2) 1996(3) 1995 1994
------------ ------------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C>
Proved developed:
Oil (MBbls)..................... 3,245 3,245 3,385 3,890 3,309
Gas (MMcf)...................... 90,254 71,643 49,491 20,408 20,582
Proved undeveloped:
Oil (MBbls)..................... 664 664 434 876 1,115
Gas (MMcf)...................... 4,269 4,269 933 9,259 3,520
Total proved:
Oil (MBbls)..................... 3,909 3,909 3,819 4,766 4,424
Gas (MMcf)...................... 94,523 75,912 50,424 29,667 24,102
Estimated pre-tax future net cash
flows (000s)....................... $271,602 $ 217,966 $ 216,154 $ 95,730 $ 59,477
============ ============= ========== ========= =========
PV-10 Value (000s)................... $194,172 $ 158,056 $ 160,171 $ 63,764 $ 41,383
============ ============= ========== ========= =========
</TABLE>
- ------------

(1) Gives effect to the Chevron Acquisition as if it occurred on October 31,
1997.

(2) Future net cash flows attributable to the Company's estimated proved
reserves and the present value of such cash flows were based on an average
gas price of $3.09 per Mcf and an average oil price of $20.09 per Bbl at
October 31, 1997. The average price received for production in the first
nine months of 1997 was $2.41 per Mcf for gas and $18.95 per Bbl for oil,
without the effects of hedging.

(3) Future net cash flows attributable to the Company's estimated proved
reserves and the present value of such cash flows were based on an average
gas price of $3.88 per Mcf and an average oil price of $23.58 per Bbl at
December 31, 1996. The average price received for production in 1996 was
$2.63 per Mcf for gas and $20.55 per Bbl for oil, without the effects of
hedging.

The Reserve Engineers prepared the estimates of proved reserves of the
Company and the future net cash flows (and present value thereof) attributable
to such proved reserves. Reserves were estimated using oil and gas prices and
production and development costs in effect on December 31 of each such year,
without escalation, and were otherwise prepared in accordance with the
Commission regulations regarding disclosure of oil and gas reserve information.

There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company and
the Reserve Engineers. The reserve data set forth in this Prospectus represent
only estimates. 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 estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, 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 estimates.
Accordingly, reserve estimates are different from the quantities of oil and gas
that are ultimately recovered. See "Risk Factors -- Estimates of Oil and Gas
Reserves."

31
<PAGE>
OIL AND GAS PRODUCTION, AVERAGE SALES PRICES AND PRODUCTION COSTS

The following table sets forth the quantities of oil and gas produced by
the Company from wells located onshore in the continental United States and
offshore in Alabama, Louisiana, Texas and federal waters.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------------------- ---------------------------------------------
1997 1996 1996 1995 1994
---------------------- --------- ---------------------- --------- ---------
PRO PRO
FORMA(1) HISTORICAL FORMA(1) HISTORICAL
-------- ---------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Production Data:
Oil (MBbls)..................... 351 351 451 585 585 594 364
Gas (MMcf)...................... 12,276 9,394 4,784 11,459 6,269 6,694 4,076
Total production (MMcfe)........ 14,379 11,497 7,490 14,970 9,781 10,261 6,260
</TABLE>
- ------------

(1) Pro forma information gives effect to the Elf Acquisition and the Chevron
Acquisition as if they occurred at the beginning of the earliest pro forma
period indicated.

The following table sets forth the Company's average sales prices,
operating data and capital expenditures for the periods indicated.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- -------------------------------
1997 1996 1996 1995 1994
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Average Sales Price Per Unit:
Oil (per Bbl)................... $ 18.83 $ 18.05 $ 18.27 $ 16.68 $ 15.63
Gas (per Mcf)................... 2.45 2.18 2.40 1.96 2.00
Total production (per Mcfe)..... 2.57 2.48 2.63 2.24 2.21
Other Operating Data per Mcfe:
Average sales price............. $ 2.57 $ 2.48 $ 2.63 $ 2.24 $ 2.21
Lease operating expenses........ 0.45 0.56 0.57 0.49 0.49
Severance taxes................. 0.09 0.20 0.20 0.17 0.16
--------- --------- --------- --------- ---------
Gross margin.................... $ 2.03 $ 1.72 $ 1.86 $ 1.58 $ 1.56
========= ========= ========= ========= =========
Capital expenditures (net)(000s)..... $ 56,629 $ 19,874 $ 36,063 $ 24,237 $ 10,412
========= ========= ========= ========= =========
</TABLE>
32
<PAGE>
PRODUCTIVE WELLS AND ACREAGE

The following table sets forth the wells drilled and completed by the
Company during the periods indicated. All such wells were drilled in the
continental United States including federal and state waters in the Gulf of
Mexico.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1996 1995 1994(1)
------------- ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development:
Oil............................. 1 .09 6 .65 7 .36
Gas............................. 2 1.52 1 .13 -- --
Non-Productive.................. -- -- -- -- 6 .42
----- ---- ----- --- ----- ---
Total...................... 3 1.61 7 .78 13 .78
===== ==== ===== === ===== ===
Exploration:
Oil............................. -- -- 1 .24 -- --
Gas............................. 1 1.0 -- -- -- --
Non-Productive.................. -- -- -- -- 1 .24
----- ---- ----- --- ----- ---
Total...................... 1 1.0 1 .24 1 .24
===== ==== ===== === ===== ===
</TABLE>
- ------------

(1) Drilling results prior to September 16, 1994 represent the combined drilling
results of the Company's predecessors.

During the ten months ended October 31, 1997 the Company drilled eight gas
wells. Two development wells (2.0 net) and one exploratory well (0.2 net) were
productive. One development well (0.7 net) and four exploratory wells (1.0 net)
were non-productive. On October 31, 1997 the Company was drilling one
development gas well (0.2 net) and two (0.6 net) exploratory gas wells.

The Company owned working and royalty interests in approximately 894 gross
(35.9 net) producing oil and 316 gross (21.2 net) producing gas wells as of
December 31, 1996. A well is categorized as an oil well or a gas well based upon
the ratio of oil to gas reserves on a Mcfe basis. However, substantially all of
the Company's wells produce both oil and gas.

The following table shows the approximate developed and undeveloped (gross
and net) leasehold acreage of the Company as of December 31, 1996.

LEASEHOLD ACREAGE
------------------------------------------
DEVELOPED UNDEVELOPED
-------------------- --------------------
STATE GROSS NET GROSS NET
- --------------------------------- --------- --------- --------- ---------
Alabama.......................... 13,136 12,210 944 190
California....................... -- -- 480 480
Louisiana........................ 46,958 5,321 8,766 6,268
Michigan......................... 4,273 185 -- --
Mississippi...................... 3,323 1,433 564 564
Oklahoma......................... 8,987 973 -- --
Texas............................ 12,390 761 -- --
Utah............................. 2,560 295 -- --
Federal Waters................... 54,962 34,553 96,075 24,019
--------- --------- --------- ---------
Total....................... 146,589 55,731 106,829 31,521
========= ========= ========= =========

As of December 31, 1996, the Company owned various royalty and overriding
royalty interests in 1,366 net developed acres and 6,953 undeveloped acres. In
addition, the Company owned 5,464 developed and 134,536 undeveloped mineral
acres.

33
<PAGE>
MAJOR CUSTOMERS

For the nine months ended September 30, 1997, Sonat Gas Marketing Co. L.P.
("Sonat Gas"), PG&E Energy Trading Corp. ("PG&E"), and Williams Energy
Services, Inc. ("Williams Energy") purchased 20%, 30%, and 10%, respectively,
of the Company's natural gas production. Williams Energy purchased natural gas
from the North Dauphin Island Field, and Sonat Gas and PG&E purchased natural
gas primarily from Callon-owned interests in federal OCS leases, Chandeleur
Block 40, Main Pass 163, and Main Pass 164/165 fields. Because of the nature of
the 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 products.

TITLE TO PROPERTIES

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

OTHER PROPERTIES

The Company's headquarters are located in Natchez, Mississippi, in
approximately 51,500 square feet of owned space. The Company also maintains
field offices in the area of the major fields in which Callon operates
properties or has a significant interest, which are owned or leased.

EMPLOYEES

The Company had 140 employees as of September 30, 1997, none of whom are
currently represented by a union. The Company considers itself to have good
relations with its employees. The Company employs ten petroleum engineers and
four petroleum geoscientists.

LITIGATION

The Company is a defendant in various legal proceedings and claims which
arise in the ordinary course of Callon's business. Callon does not believe the
ultimate resolution of such actions will have a material effect on the Company's
financial position or results of operations.

COMPETITION, MARKETS AND REGULATIONS

COMPETITION

The oil and gas industry is highly competitive in all of its phases. Callon
encounters competition from other oil and gas companies in all areas of the
Company's operations, including the acquisition of reserves and producing
properties and the marketing of oil and gas. Many of these companies possess
greater financial and other resources than the Company. The Company's
competitive position for acquiring

34
<PAGE>
producing properties is affected by the amount of funds available to the
Company, information about a producing property available to the Company and any
standards established by the Company for the minimum projected return on
investment. Because gathering systems and related facilities are the only
practical method for the intermediate transportation of gas, competition for gas
delivery is presented by other pipelines and gas gathering systems. Competition
may also be presented by alternate fuel sources.

MARKETS

Callon's ability to market oil and gas from the Company's wells depends
upon numerous factors beyond the Company's control, including the extent of
domestic production and imports of oil and gas, the proximity of the gas
production to gas pipelines, the availability of capacity in such pipelines, the
demand for oil and gas by utilities and other end users, the availability of
alternate fuel sources, the effects of inclement weather, state and federal
regulation of oil and gas production and federal regulation of gas sold or
transported in interstate commerce. No assurances can be given that Callon will
be able to market all of the oil or gas produced by the Company or that
favorable prices can be obtained for the oil and gas Callon produces.

The supply of gas capable of being produced has exceeded demand in recent
years, as a result of decreased demand for gas in response to economic factors,
conservation, lower prices for alternate energy sources and other factors. As a
result of this excess supply of gas, gas producers have experienced increased
competitive pressure and lower prices. Substantially all of the gas produced by
the Company is sold at market responsive prices.

In view of the many uncertainties affecting the supply of and demand for
oil, gas and refined petroleum products, the Company is unable to predict future
oil and gas prices and demand or the overall effect such prices and demand will
have on the Company. Callon does not believe that the loss of any of the
Company's oil purchasers would have a material adverse effect on the Company's
operations. Additionally, since substantially all of the Company's gas sales are
on the spot market, the loss of one or more gas purchasers should not materially
and adversely affect the Company's financial condition. The marketing of oil and
gas by Callon can be affected by a number of factors which are beyond the
Company's control, the exact effects of which cannot be accurately predicted.

FEDERAL REGULATIONS

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

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

Most recently, in Order No. 636, et seq., the FERC promulgated an extensive
set of new regulations requiring all interstate pipelines to "restructure"
their services. The most significant provisions of Order No. 636 require that
interstate pipelines provide firm and interruptible transportation solely on an
"unbundled" basis, separate from their sales service, and convert each
pipeline's bundled firm city-gate sales service into unbundled firm
transportation service and require that pipelines provide firm and interruptible
transportation service on a basis that is equal in quality for all gas supplies,
whether purchased from the pipeline or elsewhere. The order also recognized that
the elimination of city-gate sales service and the implementation of unbundled
transportation service would result in considerable costs being incurred by the
pipelines. Therefore, Order No. 636 provided mechanisms for the recovery by
pipelines from present, former and future customers of certain types of
"transition" costs likely to occur due to these new regulations.

35
<PAGE>
In subsequent orders, the FERC and the appellate court have substantially
upheld the requirements imposed by Order No. 636, although numerous court
appeals in which parties have sought review of separate FERC orders implementing
Order No. 636 on individual pipeline systems are still pending. In many
instances, the result of Order No. 636 and related initiatives has been to
substantially reduce or eliminate the interstate pipelines' traditional role as
wholesalers of natural gas in favor of providing only storage and transportation
services.

The FERC has announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and
request for comments concerning alternatives to its traditional cost-of-service
ratemaking methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. While the changes being
considered would affect the Company only indirectly, they are intended to
further enhance competition in natural gas markets. The Company cannot predict
what further action the FERC will take on these matters; however, the Company
does not believe that it will be affected by any action taken materially
differently than other natural gas producers.

The Outer Continental Shelf Lands Act ("OCSLA") requires that all
pipelines operating on or across the OCS provide open and non-discriminatory
access. The FERC has the authority to exercise jurisdiction under the OCSLA over
gatherers, if necessary to permit open and non-discriminatory access.

SALES AND TRANSPORTATION OF OIL. Sales of oil and condensate can be made
by the Company at market prices not subject at this time to price controls. The
price that the Company receives from the sale of these products will be affected
by the cost of transporting the products to market. As required by the Energy
Policy Act of 1992, the FERC has revised its regulations governing the rates
that may be charged by oil pipelines. The new rules, which were effective
January 1, 1995, provide a simplified, generally applicable method of regulating
such rates by use of an indexing system for setting transportation rate
ceilings. In certain circumstances, the new rules permit oil pipelines to
establish rates using traditional cost of service and other methods of rate
making. The effect that these new rules may have on the cost of moving the
Company's products to market cannot yet be determined.

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

FEDERAL, STATE OR INDIAN LEASES. In the event the Company conducts
operations on federal, state or Indian oil and gas leases, such operations must
comply with numerous regulatory restrictions, including various
nondiscrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management ("BLM") or, in the case of the
Company's OCS leases in federal waters, Minerals Management Service ("MMS") or
other appropriate federal or state agencies. The Company's OCS leases in federal
waters are administered by the MMS and require compliance with detailed MMS
regulations and orders. The MMS has promulgated regulations implementing
restrictions on various production-related activities, including restricting the
flaring or venting of natural gas. In addition, the MMS has proposed to amend
its regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization. Under certain circumstances, the MMS may require any
Company operations on federal leases to be suspended or terminated. Any such
suspension or termination could materially and adversely affect the Company's
financial condition and operations. While the MMS recently withdrew proposed
changes to the way it values natural gas for royalty payments, informal
discussions of the issue are continuing among the MMS and industry officials. It
is uncertain whether and what changes may be proposed in the future regarding
natural gas royalty valuation. In addition, the MMS has recently announced its
intention to issue a proposed rule that would require all but the smallest
producers to be capable of reporting production information electronically by
the end of 1998. The Company cannot predict what action the MMS will take on
this matter, nor can it

36
<PAGE>
predict at this stage of the proceeding how the Company might be affected by
this proposed amendment to the MMS' royalty regulations.

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

STATE REGULATIONS

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

The Company owns certain natural gas pipeline facilities that it believes
meet the traditional tests the FERC has used to establish a pipeline's status as
a gatherer not subject to FERC jurisdiction under the NGA. State regulation of
gathering facilities generally includes various safety, environmental, and in
some circumstances, nondiscriminatory take requirements, but does not generally
entail rate regulation. Natural gas gathering may receive greater regulatory
scrutiny at both state and federal levels in the post-Order No. 636 environment.

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

ENVIRONMENTAL REGULATIONS

GENERAL. The Company's activities are subject to existing federal, state
and local laws and regulations governing environmental quality and pollution
control. Activities of the Company with respect to gas facilities, including the
operation and construction of pipelines, plants and other facilities for
transporting, processing, treating or storing gas and other products, are also
subject to stringent environmental regulation by state and federal authorities
including the U.S. Environmental Protection Agency ("EPA"). Risks are inherent
in oil and gas exploration and production operations, and no assurance can be
given that significant costs and liabilities will not be incurred in connection
with environmental compliance issues; nevertheless, the Company believes that,
absent the occurrence of an extraordinary event such as those noted under "Risk
Factors," compliance with existing federal, state and local laws, rules and
regulations regulating the release of materials into the environment or
otherwise relating to the protection of the environment will not have a material
adverse effect upon the capital expenditures, earnings or the competitive
position of the Company or its operations. The Company cannot predict what
effect future regulation or legislation, enforcement policies issued thereunder,
and claims for damages to property, employees, other persons and the environment
resulting from the Company's operations could have on its activities.

SOLID AND HAZARDOUS WASTE. The Company currently owns or leases, and has
in the past owned or leased, numerous properties that for many years have been
used for the exploration and production of oil

37
<PAGE>
and gas. Although the Company believes it has utilized operating and waste
disposal practices that were standard in the industry at the time, hydrocarbons
or other solid wastes may have been disposed or released on or under the
properties owned or leased by the Company or on or under locations where such
wastes have been taken for disposal. In addition, many of these properties have
been owned or operated by third parties. The Company had no control over such
parties' treatment of hydrocarbons or other solid wastes and the manner in which
such substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under these new laws, the Company 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) or to perform remedial plugging
operations to prevent future contamination.

The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
it is possible that certain wastes generated by the Company's 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 other
applicable statutes, and therefore be subject to more rigorous and costly
operating and disposal requirements.

SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include the owner and operator
of a disposal site where a release occurred and any company that disposed or
arranged for the disposal of the hazardous substance released at the site.
CERCLA also authorizes the EPA and, in some cases, third parties, to take
actions in response to threats to the public health or the environment and to
seek to recover from the responsible classes of persons the costs of such
action. In the course of its operations, the Company has generated and will
generate wastes that may fall within CERCLA's definition of "hazardous
substances." The Company may also be an owner of sites on which "hazardous
substances" have been released. The Company may be responsible under CERCLA for
all or part of the costs to clean up sites at which such wastes have been
disposed.

OIL POLLUTION ACT. The Oil Pollution Act of 1990 (the "OPA") and
regulations thereunder impose a variety of regulations on "responsible
parties" related to the prevention of oil spills and liability for damages
resulting from such spills in United States waters. A "responsible party"
includes the owner or operator of an onshore facility, vessel or pipeline, or
the lessee or permittee of the area in which an offshore facility is located.
The OPA assigns liability to each responsible party for oil removal costs and a
variety of public and private damages. While liability limits apply in some
circumstances, a party cannot take advantage of liability limits if the spill
was caused by gross negligence or willful misconduct or resulted from violation
of a federal safety, construction or operating regulation. If the party fails to
report a spill or to cooperate fully in the cleanup, liability limits also do
not apply. Few defenses exist to the liability imposed by the OPA. The failure
to comply with OPA requirements may subject a responsible party to civil or even
criminal liability.

The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain legislative amendments to the OPA that were enacted in 1996
require owners and operators of offshore facilities that have a worst case oil
spill potential of more than 1,000 barrels to demonstrate financial
responsibility in amounts ranging from $10 million in specified state waters to
$35 million in federal OCS waters, with higher amounts, up to $150 million in
certain limited circumstances, where the MMS believes such a level is justified
by the risks posed by the quantity or quality of oil that is handled by the
facility. On March 25, 1997, the MMS promulgated a proposed rule implementing
these OPA financial responsibility requirements. The Company believes that it
currently has established adequate proof of financial responsibility for its
offshore facilities. However, the Company cannot predict whether the financial
responsibility requirements under the OPA amendments or the proposed rule will
result in the imposition of substantial additional annual costs to the Company
in the

38
<PAGE>
future or otherwise materially adversely affect the Company. The impact of the
financial responsibility requirements is not expected to be any more burdensome
to the Company than it will be to other similarly or less capitalized owners or
operators in the Gulf of Mexico.

PROHIBITION ON DISCHARGES OF PRODUCED WATER. In connection with its
exploration and production operations offshore Louisiana, the Company is subject
to a state-wide prohibition, effective July 1, 1997, against the discharge of
produced water into state coastal waters. However, the Company has received an
extension of time for complying with this prohibition until September 30, 1998
for its facilities at Chandeleur Block 25 and Main Pass Block 35, and until
October 31, 1998 for its facilities at Black Bay Complex. The Company believes
that it will be in compliance with the prohibition prior to expiration of the
applicable deadlines.

AIR EMISSIONS. The operations of the Company are subject to local, state
and federal laws and regulations for the control of emissions from sources of
air pollution. Administrative enforcement actions for failure to comply strictly
with air regulations or permits may result in the payment of civil penalties
and, in extreme cases, the shutdown of air emission sources.

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

<PAGE>
MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY

The Company currently has a Board of Directors composed of seven members.
In accordance with the Certificate of Incorporation of the Company, as amended
(the "Charter"), the members of the Board of Directors are divided into three
classes, Class I, Class II and Class III, and are elected for a full term of
office expiring at the third succeeding annual stockholders' meeting following
their election to office and when a successor is duly elected and qualified. The
terms of office of the Class I, Class II and Class III directors expire at the
annual meeting of stockholders in 1998, 1999 and 2000, respectively. The Charter
also provides that such classes shall be as nearly equal in number as possible.
The directors and executive officers of the Company are as follows:

NAME AGE PRESENT COMPANY POSITION
- ------------------------- --- ----------------------------------------
Fred L. Callon........... 47 Director; President; Chief Executive
Officer (Class III)
John S. Callon........... 77 Director; Chairman of the Board (Class
II)
Dennis W. Christian...... 51 Director; Senior Vice President; Chief
Operating Officer (Class III)
Robert A. Stanger........ 57 Director (Class I)
John C. Wallace.......... 59 Director (Class I)
B.F. Weatherly........... 53 Director (Class II)
Richard O. Wilson........ 67 Director (Class I)
John S. Weatherly........ 45 Senior Vice President; Chief Financial
Officer; Treasurer
H. Michael Tatum......... 68 Vice President; Secretary
Kathy G. Tilley.......... 52 Vice President
James O. Bassi........... 43 Corporate Controller

All of the directors, other than Messrs. Stanger and Wilson, have served as
directors since the Company's inception in 1994. Messrs. Stanger and Wilson have
served as directors since March 2, 1995.

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

Fred L. Callon is President and Chief Executive Officer of the Company and
Callon Petroleum Operating. Prior to January 1997, he was President and Chief
Operating Officer of the Company and had held that position with the Company or
its predecessors since 1984. He has been employed by the Company or its
predecessors 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 until his employment by Callon Petroleum Operating, 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.

John S. Callon is Chairman of the Board of Directors of the Company and
Callon Petroleum Operating. Effective January 2, 1997, John S. Callon retired
from his position as Chief Executive Officer of the Company. Mr. Callon founded
the Company's predecessors in 1950, and has held an executive office with the
Company or its predecessors 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.

Dennis W. Christian is Senior Vice President and Chief Operating Officer
for the Company and Callon Petroleum Operating. Prior to January 1997, he was
Senior Vice President of Operations and Acquisitions and had held that or
similar positions with the Company or its predecessors since 1981. Prior to
joining Callon Petroleum Operating, 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.

40
<PAGE>
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 &
Lybrand in Canada in 1963, after which he joined Baring Brothers & Co., Limited
in London, England. For more than the last ten years, he has served as Chairman
of Fred. Olsen Ltd., a London-based corporation which he joined in 1968, where
he has specialized in the business of shipping and property development. He is a
director of Fred. Olsen Energy ASA, Oslo, a publicly held energy service
company, Harland & Wolff PLC, Belfast, Ganger Rolf ASA and Bonheur ASA, Oslo,
publicly-traded shipping companies. He is an executive officer of NOCO
Management, Ltd., the general partner of NOCO and a director of other companies
associated with Fred. Olsen Interests.

B. F. Weatherly is a principal of Amerimark Capital Group, Houston, Texas,
an investment banking firm. He is an executive officer of NOCO Management Ltd.,
the general partner of the general partner of NOCO. 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 associated with
Fred. Olsen Interests. From 1989 to 1991, he was partner in Amerimark Capital
Corp., a Dallas investment banking firm. He holds a Master of Accountancy degree
from the 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 for the past eleven years has been Chairman of O.G.C.
International P.L.C., a Scottish public company engaged in the offshore oil and
gas maintenance and construction business headquartered in Aberdeen, Scotland
and recently acquired by Halliburton, Inc. After 13 years, Mr. Wilson has
retired from the chairmanship of Dolphin A/S, Stavanger, Norway, and Dolphin
Drilling Ltd., Aberdeen, Scotland, both offshore drilling companies owned by
Fred. Olsen Interests. He is also Chairman of Belmont Constructors, Inc., a
Houston, Texas-based industrial contractor associated with Fred. Olsen
Interests. 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.

John S. Weatherly is Senior Vice President, Chief Financial Officer and
Treasurer for the Company and Callon Petroleum Operating. Prior to April 1996,
he was Vice President, Chief Financial Officer and Treasurer of the Company and
had held those positions since 1983. Prior to joining Callon Petroleum Operating
in August 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.

H. Michael Tatum is Vice President and Secretary for the Company and Callon
Petroleum Operating and is responsible for management of administrative matters.
Mr. Tatum has held this position with the Company or its predecessors since
1976, and has been employed by Callon Petroleum Operating 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 Vice President of Acquisitions and New Ventures for the
Company and Callon Petroleum Operating and has held that position since April
1996. She was employed by Callon Petroleum Operating in December 1989 as manager
of acquisitions and prior thereto held that or similar positions as a consultant
from 1981. Ms. Tilley received her B.A. degree in economics from Louisiana State
University in 1967.

41
<PAGE>
James O. Bassi is Corporate Controller of the Company and Callon Petroleum
Operating. Prior to being appointed to that position in June, 1997, he was
Manager of the Accounting Department for the Company and Callon Petroleum
Operating. Mr. Bassi has been employed by the Company and its predecessors for a
total of nine years. Prior to his employment by Callon Petroleum Operating, 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.

Messrs. John S. Callon and Fred L. Callon, as nominees of the Callon
Family, and Messrs. B. F. Weatherly and John C. Wallace, as nominees of NOCO,
were elected to the Board of Directors pursuant to the terms of a Stockholders'
Agreement dated September 16, 1994. See "Principal Stockholders --
Stockholders' Agreement."

All officers and directors of the Company are United States citizens,
except Mr. Wallace, who is a citizen of Canada.

42
<PAGE>
PRINCIPAL STOCKHOLDERS

The following table sets forth, as of September 30, 1997, certain
information with respect to the ownership of shares of Common Stock and the
Company's Series A Preferred Stock as to (i) all persons known by the Company to
be the beneficial owners of 5% or more of the outstanding shares of Common
Stock, (ii) each director, (iii) all executive officers, and (iv) all executive
officers and directors of the Company as a group. Information set forth in the
table with respect to beneficial ownership of Common Stock and Series A
Preferred Stock has been obtained from filings made by the named beneficial
owners with the Commission or, in the case of executive officers and directors
of the Company, has been provided to the Company by such individuals.
<TABLE>
<CAPTION>
COMMON STOCK PREFERRED STOCK
------------------------ ------------------------
AMOUNT AND AMOUNT AND
NAME AND NATURE OF NATURE OF
ADDRESS OF BENEFICIAL PERCENT BENEFICIAL PERCENT
BENEFICIAL OWNER(S) OWNERSHIP OF CLASS OWNERSHIP OF CLASS
- ---------------------------------------- ---------- -------- ---------- --------
<S> <C> <C>
DIRECTORS:
John S. Callon..................... 317,040(2) 5.18% -- --
Fred L. Callon..................... 733,768(3) 11.98 -- --
Dennis W. Christian................ 129,000(4) 2.11 -- --
Robert A. Stanger.................. 20,856(5) * -- --
John C. Wallace.................... 2,007,883(6) 33.30 -- --
B.F. Weatherly..................... 165,739(7) 2.74 -- --
Richard O. Wilson.................. 169,145(8) 2.80 1,000 *

EXECUTIVE OFFICERS:
John S. Weatherly.................. 123,896(9) 2.01 -- --
H. Michael Tatum................... 43,000(10) *
Kathy G. Tilley.................... 86,147(11) 1.41 -- --
James O. Bassi..................... 15,600(12) *

DIRECTORS AND EXECUTIVE OFFICERS AS A
GROUP (11 PERSONS).................... 3,521,330(13) 53.94 1,000 *

CERTAIN BENEFICIAL OWNERS:
Fred. Olsen Energy ASA............. 1,839,386(14) 30.51 -- --
Fred. Olsensgate 2
0152 Oslo, Norway
Wellington Management Company...... 607,704(15) 9.22 247,690 18.83
75 State Street
Boston, Massachusetts 02109
</TABLE>
- ------------

* Less than 1%

(1) Unless otherwise indicated, each of the above persons may be deemed to have
sole voting and dispositive power with respect to such shares.

(2) Of the 317,040 shares beneficially owned by John S. Callon, 97,040 are
owned directly by him and he has sole voting and dispositive power over
such shares, 105,000 shares are held in a family limited partnership,
90,000 shares are subject to options under the Company's 1994 Plan
exercisable within 60 days and 25,000 shares are subject to a restricted
stock agreement and vest 20% annually beginning January 2, 1998. Shares
indicated as owned by John S. Callon do not include shares of Common Stock
owned by NOCO and F.O. Energy and shares of Common Stock owned by certain
other members of the Callon Family including 61,837 shares owned by John S.
Callon's wife and over which he disclaims beneficial ownership. Under the
terms of the Stockholder's Agreement among the Callon Family and NOCO dated
September 16, 1994, and subsequently amended to include F.O. Energy, John
S. Callon and the other members of the Callon Family have the right of
first refusal to acquire

(FOOTNOTES CONTINUED ON FOLLOWING PAGE)

43
<PAGE>
shares of Common Stock proposed to be sold by NOCO or F.O. Energy under
certain circumstances and all parties to the Stockholders' Agreement have
agreed to support two directors nominated by the Callon Family and two
directors nominated by NOCO. John S. Callon disclaims beneficial ownership
of the NOCO or F.O. Energy shares.

(3) Of the 733,768 shares beneficially owned by Fred L. Callon, 201,556 shares
are owned directly by him; 268,016 shares are held by him as custodian for
certain minor Callon Family members; 78,430 shares are held by him as
trustee of certain Callon Family trusts; 80,000 shares are subject to
options under the 1994 Plan exercisable within 60 days; 15,000 shares are
subject to options under the 1996 Plan exercisable within 60 days; 60,000
shares represent performance shares issued under the 1996 Plan which do not
vest until January 1, 2001; and 30,766 shares are held by Fred L. Callon as
Trustee of shares held by the Callon Petroleum Company Employee Savings and
Protection Plan. Shares indicated as owned by Fred L. Callon do not include
shares of Common Stock owned by NOCO and F.O. Energy and shares of Common
Stock owned by other members of the Callon Family, including 25,009 shares
owned by Fred L. Callon's wife over which he disclaims beneficial
ownership. Under the terms of the Stockholders' Agreement, Fred L. Callon
and the other members of the Callon Family have the right of first refusal
to acquire shares of Common Stock proposed to be sold by NOCO or F.O.
Energy under certain circumstances and all parties to the Stockholders'
Agreement have agreed to support two directors nominated by the Callon
Family and two directors nominated by NOCO. Fred L. Callon disclaims
beneficial ownership of these shares.

(4) Includes 60,000 shares subject to options under the 1994 Plan and 14,000
shares subject to options under the 1996 Plan, all of which are exercisable
within 60 days, and 55,000 shares represent performance shares awarded
under the 1996 Plan which do not vest until January 1, 2001.

(5) Includes 15,000 shares subject to options under the 1994 Plan and 5,000
shares subject to options under the 1996 Plan, all of which are exercisable
within 60 days.

(6) Includes 3,125 shares owned directly by John C. Wallace, 15,000 shares
subject to options under the 1994 Plan and 5,000 shares subject to options
under the 1996 Plan, all of which are exercisable within 60 days, and
145,372 shares owned by NOCO and 1,839,386 shares owned by F.O. Energy. See
note (14) below.

(7) Includes 367 shares owned directly by B.F. Weatherly, 15,000 shares subject
to options under the 1994 Plan and 5,000 shares subject to options under
the 1996 Plan, all of which are exercisable within 60 days, and 145,372
shares owned by NOCO. See note (14) below.

(8) Includes 1,500 shares owned directly by Richard O. Wilson, 15,000 shares
subject to options under the 1994 Plan and 5,000 shares subject to options
under the 1996 Plan, all of which are exercisable within 60 days, 2,273
shares issuable upon conversion of 1,000 shares of Series A Preferred Stock
and 145,372 shares owned by NOCO. See note (14) below.

(9) Includes 217 shares which are held by Mr. Weatherly as custodian for his
minor children, 60,000 shares subject to options under the 1994 Plan,
13,000 shares subject to options under the 1996 Plan, all of which are
exercisable within 60 days, and 50,000 shares represent a performance share
award under the 1996 Plan which do not vest until January 1, 2001.

(10) Includes 25,000 shares subject to options under the 1994 Plan, 3,000 shares
subject to options under the 1996 Plan, all of which are exercisable within
60 days, and 15,000 Shares represent a performance share award under the
1996 Plan which do not vest until January 1, 2001.

(11) Includes 30,000 shares subject to options under the 1994 Plan, 11,000
shares subject to options under the 1996 Plan, all of which are exercisable
within 60 days and 45,000 shares represent a performance share award under
the 1996 Plan which do not vest until January 1, 2001.

(12) Includes 11,000 shares subject to options under the 1994 Plan and 4,600
shares subject to options under the 1996 Plan, all of which are exercisable
within 60 days.

(13) Includes 416,000 shares subject to options under the 1994 Plan, 80,600
shares subject to options under the 1996 Plan, all of which are exercisable
within 60 days, 225,000 shares represent performance share awards under the
1996 Plan which do not vest until January 1, 2001 and 25,000 shares subject
to a restricted stock agreement.

(14) As of August 11, 1997, NOCO Enterprises, L.P. distributed 1,839,386 shares
of Common Stock to its sole limited partner, NOCO Holdings, L.P. ("NOCO
Holdings") and NOCO Holdings distributed

(FOOTNOTES CONTINUED ON FOLLOWING PAGE)

44
<PAGE>
those shares to its general partner and to certain of its limited partners.
The general partner of NOCO Holdings distributed the shares of Common Stock
it received to Fred. Olsen Finance Limited, a limited partner of NOCO
Holdings, and all of the limited partners of NOCO Holdings exchanged their
shares of Common Stock for shares in F.O. Energy and Fred. Olsen Energy II
AS. Subsequently, Fred. Olsen Energy II AS merged with F.O. Energy. As
disclosed on a Schedule 13D dated August 20, 1997, F.O. Energy has the sole
power to vote and the sole power to dispose of 1,839,386 shares of Common
Stock of the Company. Ganger Rolf ASA, a public joint stock company
organized and existing under the laws of the Kingdom of Norway and the
owner of 100% of the outstanding capital stock of F.O. Energy ("Ganger
Rolf") and Bonheur ASA, a public joint stock company organized and
existing under the laws of the Kingdom of Norway and the owner of 49.0% of
the outstanding capital stock of Ganger Rolf ("Bonheur"), each have the
power to direct the vote and disposition of the shares of Common Stock of
the Company owned by F.O. Energy. AIS Quatro, a joint stock company
organized and existing under the laws of the Kingdom of Norway and the
owner of 6.7% of the outstanding capital stock of Ganger Rolf and 23.0% of
the outstanding capital stock of Bonheur ("Quatro") and AIS Cinco, a
joint stock company organized and existing under the laws of the Kingdom of
Norway and the owner of 6.9% of the outstanding capital stock of Ganger
Rolf and 23.0% of the outstanding capital stock of Bonheur, each disclaims
beneficial ownership of the shares of Common Stock of the Company owned by
F.O. Energy. John C. Wallace, a director of the Company, is a director of
F.O. Energy and a director of Ganger Rolf, Bonheur, Quatro and Cinco and as
a result, may be deemed to share the power to vote and dispose of, and
therefore be a beneficial owner of the shares of Common Stock owned by F.O.
Energy. The principal business address and principal executive offices of
Ganger Rolf, Bonheur, Quatro and Cinco are located at Fred. Olsensgate 2,
0152 Oslo, Norway and the address of John C. Wallace is 65 Vincent Square,
London England SWIP 2RY. In connection with F.O. Energy's acquisition of
the shares of Common Stock of the Company, F.O. Energy has become a party
to the Stockholders' Agreement. See " -- Stockholders' Agreement".
Because of the Stockholders' Agreement, NOCO and certain of its affiliates,
F.O. Energy, Ganger Rolf, Bonheur, Quatro and Cinco and members of the
Callon Family may be deemed to be a "group" for purposes of beneficial
ownership under Commission regulations. If such a group were deemed to
exist, it would beneficially own over 60% of the Common Stock.

(15) Includes 563,000 shares issuable upon conversion of 247,690 shares of
Series A Preferred Stock.

STOCKHOLDERS' AGREEMENT

Pursuant to the Stockholders' Agreement among the Callon Family, NOCO and
F.O. Energy, the Callon Family, on the one hand, and NOCO and F.O. Energy, on
the other, each elect two directors to the Company's Board of Directors.
Specifically, the Stockholders' Agreement provides that the Callon Family, on
the one hand, and NOCO and F.O. Energy, on the other, shall use their best
efforts, including voting the shares of Common Stock which they own, to cause
the Company's Board of Directors to be composed of at least four members, two of
such members to be selected by the Callon Family and two of such members to be
selected by NOCO and F.O. Energy. The Stockholders' Agreement also contains
restrictions on transfer of shares of Common Stock owned by the Callon Family,
NOCO and F.O. Energy and prohibits the Callon Family, NOCO and F.O. Energy from
taking certain actions which would result in certain changes of control or
fundamental changes, without the consent of the other party.

As a result of the Stockholders' Agreement, the Callon Family, on the one
hand, and the Callon Family, NOCO and F.O. Energy on the other, may be deemed to
form a "group" for purposes of beneficial ownership under Commission
regulations. The Callon Family disclaims beneficial ownership of the Common
Stock owned by NOCO and F.O. Energy. In addition, each Callon Family stockholder
disclaims beneficial ownership of all shares of Common Stock owned by the other
Callon Family stockholders and the existence of a group comprised of the Callon
Family stockholders. If NOCO, F.O. Energy and the Callon Family were deemed to
be a group, it would beneficially own more than 60% of the outstanding Common
Stock.

45
<PAGE>
DESCRIPTION OF OUTSTANDING SECURITIES AND DEBT INSTRUMENTS

COMMON STOCK

The Company is authorized by its Charter to issue up to 20,000,000 shares
of Common Stock, $0.01 par value. As of September 30, 1997, 6,028,994 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. Such
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 securities of the Company. In the
event of a liquidation, dissolution or winding up of the Company, holders of
Common Stock are entitled to share equally and ratably in all of the assets
remaining, if any, after satisfaction of all debts and liabilities of the
Company, 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

The Company is authorized by its Charter to issue 2,500,000 shares of
preferred stock, $0.01 par value per share. The 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 voluntary liquidation, dissolution or winding up of the affairs
of the Company, conversions rights and voting powers. The Company has 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").

SERIES A PREFERRED STOCK

In November 1995, the Company issued and sold 1,315,500 shares of its
Series A Preferred Stock. The following description of the Series A Preferred
Stock is qualified in its entirety by the Certificate of Designations dated
November 22, 1995, a copy of which is filed as an exhibit to the Company's Form
10-K for fiscal year ended December 31, 1995.

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 the Company ranking junior to the Series A Preferred Stock, nor may any
Common Stock or any other stock of the Company ranking junior to or on a parity
with the Series A Preferred Stock be redeemed, purchased or otherwise acquired
for any consideration by the Company (except by conversion into or exchange for
stock of the Company 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. The Company from time to time may
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 the best interests
of the Company. 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. The Company or its successor may elect to distribute cash to
such holders in lieu of Common Stock at an equal value.

46
<PAGE>
EXCHANGE. The Series A Preferred Stock may be exchanged at the option of
the Company 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 the Company 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 directors of the Company 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, the Company 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.

CONVERTIBLE DEBENTURES

The Company may, at its option, exchange its Convertible Debentures for its
Series A Preferred Stock. If issued, the Convertible Debentures will be issued
under an indenture between the Company and Bank One, Columbus, NA, as trustee, a
copy of which is filed as an exhibit to the Company's Form 10-K for fiscal year
1996. The statements below are summaries of certain provisions of such indenture
and the Convertible Debentures, do not purport to be complete and are qualified
in their entirety by such reference.

GENERAL. The Convertible Debentures will be unsecured, subordinated
obligations of the Company, limited in aggregate principal amount to the
aggregate liquidation preference of the Series A Preferred Stock and will mature
on December 31, 2010. The Company will 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. The Company
from time to time may reduce the conversion price in order that certain
stock-related distributions, which may be made by the Company to its
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 the Company.
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,
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 the option of the Company 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

47
<PAGE>
(i) failure to pay principal or premium, if any, on any Convertible Debenture
when due at maturity, upon redemption or otherwise; (ii) failure to pay an
interest on any Convertible Debenture when due and continuing for 30 days; (iii)
breach of such indenture or Convertible Debentures by the Company; (iv) certain
events in bankruptcy, insolvency or reorganization; (v) default on indebtedness
(other than non-recourse indebtedness) resulting in more than $7,500,000
becoming due and payable prior to its maturity; or (vi) a judgment or decree
entered against the Company involving a liability of $7,500,000 or more.

CREDIT FACILITY

Effective October 31, 1996, the Company amended and restated its Credit
Facility which is secured by mortgages covering substantially all of the
Company's producing oil and gas properties. The Credit Facility provides for
borrowings of a maximum of the lesser of $50 million and an initial Borrowing
Base of $30 million which is adjusted periodically on the basis of a discounted
present value attributable to the Company's proven 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 either Prime
or Prime plus 0.50%. Prime is the prime commercial lending rate announced from
time to time by the lender. The Company, at its option, may fix the interest
rate on all or a portion of the outstanding principal balance at either 1.00% or
1.375% above an agreement-defined "Eurodollar" rate, depending upon the
percentage of the unused portion of the Borrowing Base, for periods of up to six
months. The weighted average interest rate for the total debt outstanding at
September 30, 1997 was 8.50%. 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.

Borrowings under the Credit Facility are guaranteed by certain of the
Company's subsidiaries. The Credit Facility has certain customary covenants
including, but not limited to, covenants with respect to the following matters:
(i) limitation on restricted payments, distributions and investments; (ii)
limitations on guarantees and indebtedness; (iii) limitation on prepayments of
subordinated indebtedness; (iv) limitation on prepayments of additional
indebtedness; (v) limitation on mergers and issuances of securities; (vi)
limitation on sales of property; (vii) limitation on transactions with
affiliates; (viii) limitation on derivative contracts; (ix) limitation on
acquisitions, new businesses and margin stock; and (x) limitation with respect
to certain prohibited types of contracts and multi-employer ERISA plans. The
Company is also required to maintain certain financial ratios and conditions,
including without limitation an EBITDA to debt service coverage ratio, a net
worth requirement and a funded debt to capitalization ratio.

10% NOTES

On November 27, 1996, the Company issued $24,150,000 aggregate principal
amount of 10% Senior Subordinated Notes due December 15, 2001 (the "10%
Notes"). The Company used the proceeds to reduce borrowings under the Credit
Facility and for other corporate purposes. Interest is payable quarterly on
March 15, June 15, September 15 and December 15 of each year. The 10% 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 10% Notes are general unsecured obligations
of the Company, subordinated in right of payment to all existing and future
indebtedness of the Company. See "Notes to Consolidated Financial
Statements -- Note 5."

10.125% NOTES

48
<PAGE>
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, and $36 million
principal amount of Series A Notes were exchanged for $36 million principal
amount of Series B Notes. 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 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 indenture for the 10.125% Notes contain various covenants
including restrictions on additional indebtedness and payment of cash dividends
as well as maintenance of certain financial ratios.

49
<PAGE>
UNDERWRITING

Subject to the terms and conditions of the Underwriting Agreement among the
Company and the Underwriters named below (the "Underwriting Agreement"), the
Company has agreed to sell to each of such Underwriters named below, and each of
such Underwriters has severally agreed to purchase from the Company, the
respective number of shares of Common Stock set forth opposite its name below.

NUMBER OF
UNDERWRITERS SHARES
- ------------------------------------- ---------
Morgan Keegan & Company, Inc......... 400,000
A.G. Edwards & Sons, Inc............. 400,000
Howard, Weil, Labouisse, Friedrichs
Incorporated....................... 400,000
Jefferies & Company, Inc............. 400,000
---------
Total........................... 1,600,000
=========

Under the terms and conditions of the Underwriting Agreement, the
underwriters are committed to take and pay for all of the shares of Common Stock
offered hereby, if any are taken.

The Underwriters propose to offer the shares of Common Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus, and in part to certain securities dealers at such
price less a concession of $0.48 per share. The Underwriters may allow, and such
dealers may allow, a concession not in excess of $0.10 per share to certain
brokers and dealers. After the shares of Common Stock are released for sale to
the public, the offering price and other selling terms may from time to time be
varied by the Underwriters.

The Company has granted the Underwriters an option exercisable for 30 days
after the date of this Prospectus to purchase up to an aggregate of 240,000
additional shares of Common Stock solely to cover over-allotments, if any. If
the Underwriters exercise their over-allotment option, the Underwriters have
severally agreed, subject to certain conditions, to purchase approximately the
same percentage thereof that the number of shares of Common Stock to be
purchased by each of them, as shown in the table above, bears to the 1,600,000
shares of Common Stock.

The Company has agreed in the Underwriting Agreement not to offer, sell,
contract to sell, grant any option to purchase or otherwise dispose of any
shares of Common Stock or any securities convertible into or exercisable or
exchangeable for Common Stock, subject to certain limited exceptions, for a
period of 90 days after the date of this Prospectus without the prior written
consent of Morgan Keegan & Company, Inc. In addition, the Company's directors
and executive officers, NOCO and F.O. Energy have agreed not to sell, contract
to sell, grant any option to purchase or otherwise dispose of any shares of
Common Stock or any securities convertible into or exercisable or exchangeable
for Common Stock, other than as gifts, pledges and certain other transfers to
persons who agree to the same restrictions for a period of 90 days after the
date of this Prospectus without the prior written consent of Morgan Keegan &
Company, Inc.

In connection with this Offering, the Underwriters may engage in
transactions that stabilize, maintain or otherwise affect the market price of
the Common Stock. Such transactions may include stabilization transactions
pursuant to which the Underwriters may bid for or purchase Common Stock for the
purpose of stabilizing its market price. The Underwriters also may create a
short position for the account of the Underwriters by selling more Common Stock
in connection with the Offering than they are committed to purchase from the
Company, and in such case the Underwriters may purchase Common Stock in the open
market following completion of the Offering to cover all or a portion of such
short position. The Underwriters may also cover all or a portion of such short
position by exercising the Underwriters' over-allotment option referred to
above. In addition, the Underwriters may impose "penalty bids"whereby selling
concessions allowed to syndicate members or other broker-dealers for the Shares
sold in the Offering for their account may be reclaimed by the syndicate if such
Shares are repurchased by the syndicate in stabilizing or covering transactions.
Any of the transactions described in this paragraph may result in the
maintenance of the price of the Common Stock at a level above that which might
otherwise prevail in the

50
<PAGE>
open market. The imposition of a penalty bid might also affect the price of the
Common Stock to the extent that it could discourage resales of the security.
Neither the Company nor any of the Underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the transactions
described above may have on the price of the Common Stock. In addition, neither
the Company nor any of the Underwriters make any representation that the
Underwriters will engage in such transactions or that such transactions, once
commenced, will not be discontinued without notice.

In connection with this Offering, the Underwriters or their respective
affiliates and selling group members (if any) who are qualified market makers on
Nasdaq may engage in "passive market making" in the Common Stock on Nasdaq in
accordance with Rule 103 of Regulation M under the Exchange Act. Rule 103
permits, upon the satisfaction of certain conditions, underwriters and selling
group members participating in a distribution that are also Nasdaq market makers
in the security being distributed (or a related security) to engage in limited
market making transactions during the period when Regulation M under the
Exchange Act would otherwise prohibit such activity. Rule 103 prohibits
underwriters and selling group members engaged in passive market making
generally from entering a bid or effecting a purchase at a price that exceeds
the highest bid for those securities displayed on Nasdaq by a market maker that
is not participating in the distribution. Under Rule 103, each underwriter or
selling group member engaged in passive market making is subject to a daily net
purchase limitation equal to 30% of such entity's average daily trading volume
during the two full consecutive calendar months immediately preceding the date
of the filing of the registration statement under the Securities Act pertaining
to the security to be distributed (or such related security).

The Company has agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act or to
contribute to payments the Underwriters may be required to make in respect of
such liabilities.

LEGAL MATTERS

Certain legal matters with respect to the Common Stock offered hereby have
been passed upon for the Company by Butler & Binion, L.L.P., Houston, Texas.
Certain legal matters will be passed upon for the Underwriters by Vinson &
Elkins L.L.P., Houston, Texas.

EXPERTS

The historical financial statements of the Company as of December 31, 1995
and 1996, and for each of the three years in the period ended December 31, 1996,
included in this Prospectus have been audited by Arthur Andersen LLP,
independent public accountants, as stated 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 statement of revenues and direct operating expenses of the working
interest in Mobile Block 864 Area acquired by Callon Petroleum Operating for the
year ended December 31, 1996 included in this Prospectus has been audited by
Ernst & Young LLP, independent auditors, as set forth in their report thereon
appearing elsewhere herein, and is included in reliance upon such report given
upon the authority of said firm as experts in accounting and auditing.

The statement of revenues and direct operating expenses of 61% of Chevron
U.S.A. Inc.'s working interest in Mobile 864 Unit Outer Continental Shelf
acquired by Callon Petroleum Operating Company for each of the three years in
the period ended December 31, 1996 included in this Prospectus has been so
included in reliance on the report of Price Waterhouse LLP, independent
accountants, given on the authority of said firm as experts in auditing and
accounting.

The information appearing in this Prospectus regarding quantities of
reserves 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.

51
<PAGE>
AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Exchange
Act, and in accordance therewith files reports, proxy statements and other
information with the Commission. Such reports and other information may be
inspected and copied at the public reference facilities of the Commission, Room
1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, as well
as at the following Regional Offices: 7 World Trade Center, Suite 1300, New
York, New York 10048, and Citicorp Center, 500 West Madison Street, Suite 1400,
Chicago, Illinois 60661. Copies of such materials can be obtained from the
Commission by mail at prescribed rates. Requests should be directed to the
Commission's Public Reference Section, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549. The Commission also maintains a website at
http://www.sec.gov that contains reports, proxy statements, and other
information. Callon's Common Stock is listed on the Nasdaq Stock Market.
Reports, proxy and information statements and other information relating to
Callon can be inspected at the offices of the National Association of Securities
Dealers, Inc., 1735 K Street, N.W., Washington, D.C. 20006.

This Prospectus constitutes a part of a registration statement on Form S-2
(the "Registration Statement") filed by the Company with the Commission under
the Securities Act. This Prospectus does not contain all the information set
forth in the Registration Statement, certain parts of which are omitted in
accordance with the rules and regulations of the Commission, and reference is
hereby made to the Registration Statement and to the exhibits relating thereto
for further information with respect to the Company and the Notes. Any
statements contained herein concerning the provisions of any document are not
necessarily complete, and, in each instance, reference is made to a copy of such
document filed as an exhibit to the Registration Statement or otherwise filed
with the Commission. Each such statement is qualified in its entirety by such
reference.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents filed by the Company with the Commission pursuant
to the Exchange Act (file number 0-25192) are incorporated herein by reference,
except as superseded or modified herein:

(i) The Company's Annual Report on Form 10-K for the year ended
December 31, 1996;

(ii) The Company's Quarterly Reports on Form 10-Q for the quarterly
periods ended March 31, 1997, June 30, 1997 and September 30, 1997;

(iii) The Company's Current Report on Form 8-K filed January 15,
1997; the Company's Current Report on Form 8-K filed July 11, 1997 as
amended by the Company's Current Report on Form 8-K/A filed August 8, 1997;
and the Company's Current Report on Form 8-K filed August 8, 1997; and the
Company's Current Report on Form 8-K filed November 4, 1997 as amended by
the Company's Current Report on Form 8-K/A filed November 21, 1997; and

(iv) The Company's Registration Statement on Form 8-B filed October
3, 1994.

All reports and other documents subsequently filed by the Company pursuant
to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this
Prospectus and prior to the termination of this Offering shall be deemed to be
incorporated by reference herein and to be a part hereof from the date of filing
of such reports and documents. Any statement contained herein or in a document
incorporated or deemed to be incorporated herein by reference shall be deemed to
be modified or superseded for purposes of this Prospectus to the extent that a
statement contained in this Prospectus or in any subsequently filed document
(which is deemed to be incorporated by reference herein) modifies or supersedes
such statement. Any such statement so modified or superseded shall not be
deemed, except as so modified or superseded, to constitute a part of this
Prospectus.

To the extent the information relating to the Company contained in this
Prospectus summarizes, is based upon or refers to, information and financial
statements contained in one or more of the documents incorporated by reference
herein, the information contained herein is qualified in its entirety by
reference to such document, and it should be read in conjunction therewith.

52
<PAGE>
The Company will provide, without charge, to each person to whom a copy of
this Prospectus is delivered, on the written or oral request of such person, a
copy of any or all of the documents incorporated herein by reference (other than
exhibits thereto, unless such exhibits are specifically incorporated by
reference into the information that this Prospectus incorporates). Written or
telephone requests for such copies should be directed to the Company's principal
office: Callon Petroleum Company, 200 North Canal Street, Natchez, Mississippi
39120, (601) 442-1601.

53
<PAGE>
GLOSSARY

The following definitions shall apply to the technical terms used in this
Prospectus.

"BBLS" means barrels.

"BBLS/D" means barrels per day.

"BCF" means billion cubic feet.

"BCFE" means billion cubic feet equivalent, determined using the ratio of
six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

"GROSS" means the number of wells or acres in which the Company has an
interest.

"MBBLS" means thousands of barrels.

"MCF" means thousands of cubic feet. Gas volumes are stated at the legal
pressure base of the state or area in which the reserves are located at 60
degrees Fahrenheit.

"MCF/D" means thousand cubic feet per day.

"MCFE" means thousand cubic feet equivalent, determined using the ratio
of six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

"MMBBLS" means millions of barrels.

"MMBTU" means a million British thermal units. A British thermal unit is
the heat required to raise the temperature of a one-pound mass of water from
59.5 to 60.5 degrees Fahrenheit under specified conditions.

"MMCF" means millions of cubic feet.

"MMCF/D" means millions of cubic feet per day.

"MMCFE" means million cubic feet equivalent, determined using the ratio
of six Mcf of gas to one barrel of oil, condensate or natural gas liquids.

"MMCFE/D" means million cubic feet equivalent per day.

"NET" is determined by multiplying gross wells or acres by the Company's
working interest in such wells or acres.

"PV-10 VALUE" means the pre-tax, present value, discounted at 10%, of
future net cash flows from estimated proved reserves, calculated holding prices
and costs constant at amounts in effect on the date of the report (unless such
prices or costs are subject to change pursuant to contractual provisions).

"RESERVE REPLACEMENT COSTS," expressed in dollars per Mcfe, is calculated
by dividing the amount of total capital expenditures for oil and gas activities
by the amount of proved reserves added during the same period (including the
effect on proved reserves of reserve revisions).

<PAGE>
INDEX TO FINANCIAL STATEMENTS

PAGE
----

Callon Petroleum Company
(historical):

Report of Independent Public
Accountants.................... F-2

Consolidated Balance Sheets as
of September 30, 1997 and
December 31, 1996 and 1995..... F-3

Consolidated Statements of
Operations for the Nine Months
Ended September 30, 1997 and
1996 and for the Years Ended
December 31, 1996, 1995 and
1994........................... F-4

Consolidated Statements of
Stockholders' Equity for the
Nine Months Ended September 30,
1997 and for the Years Ended
December 31, 1996, 1995 and
1994........................... F-5

Consolidated Statements of Cash
Flows for the Nine Months Ended
September 30, 1997 and 1996 and
for the Years Ended December
31, 1996, 1995 and 1994........ F-6

Notes to Consolidated Financial
Statements..................... F-7

Callon Petroleum Company (pro forma):

Introduction.................... F-21

Unaudited Pro Forma Condensed
Consolidated Balance Sheet as
of September 30, 1997.......... F-22

Unaudited Pro Forma Consolidated
Statement of Operations for the
Year Ended
December 31, 1996............. F-23

Unaudited Pro Forma Consolidated
Statement of Operations for the
Nine Months Ended September 30,
1997........................... F-24

Notes to Unaudited Pro Forma
Consolidated Financial
Statements..................... F-25

Elf Acquisition

Report of Independent
Auditors....................... F-26

Statement of Revenues and Direct
Operating Expenses for the Year
Ended December 31, 1996........ F-27

Notes to Statement of Revenues
and Direct Operating
Expenses....................... F-28

Chevron Acquisition

Report of Independent
Accountants.................... F-30

Statement of Revenues and Direct
Operating Expenses for the
Years Ended
December 31, 1996, 1995 and
1994........................... F-31

Notes to Statement of Revenues
and Direct Operating
Expenses....................... F-32

F-1

<PAGE>
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,
1996 and 1995, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
February 19, 1997

F-2
<PAGE>
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
SEPTEMBER 30, --------------------------
1997 1996 1995
------------- ------------ ------------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents....... $ 5,939 $ 7,669 $ 4,265
Accounts receivable............. 9,621 12,661 8,329
Other current assets............ 738 516 238
------------- ------------ ------------
Total current assets....... 16,298 20,846 12,832
------------- ------------ ------------
Oil and gas properties, full cost
accounting method:
Evaluated properties............ 374,113 322,970 304,737
Less accumulated depreciation,
depletion and amortization.... (277,771) (266,716) (257,143)
------------- ------------ ------------
96,342 56,254 47,594
Unevaluated properties excluded
from amortization............. 30,954 26,235 10,171
------------- ------------ ------------
Total oil and gas
properties................. 127,296 82,489 57,765
------------- ------------ ------------
Pipeline and other facilities, net... 6,585 6,618 5,371
Other property and equipment, net.... 1,841 1,594 1,633
Deferred tax asset................... 2,486 5,412 5,462
Long-term gas balancing receivable... 246 660 619
Other assets, net.................... 1,598 901 185
------------- ------------ ------------
Total assets............... $ 156,350 $ 118,520 $ 83,867
============= ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued
liabilities..................... $ 8,203 $ 8,273 $ 3,131
Undistributed oil and gas
revenues........................ 2,434 2,260 2,153
Accrued net profits interest
payable (Note 9)................ 2,035 5,435 2,836
------------- ------------ ------------
Total current
liabilities................ 12,672 15,968 8,120
------------- ------------ ------------
Long-term debt....................... 60,250 24,250 100
Deferred income...................... 233 48 86
Long-term gas balancing payable...... 313 390 432
------------- ------------ ------------
Total liabilities.......... 73,468 40,656 8,738
------------- ------------ ------------
Stockholders' equity:
Preferred Stock, $0.01 par
value; 2,500,000 shares
authorized; 1,315,500 shares
of Convertible Exchangeable
Preferred Stock, Series A
issued and outstanding with a
liquidation preference of
$32,887,500 (Note 11)......... 13 13 13
Common Stock, $0.01 par value;
20,000,000 shares authorized;
6,028,994 at September 30,
1997 and 5,758,667 and
5,754,529 shares outstanding
at December 31, 1996 and 1995,
respectively.................. 60 58 58
Unearned compensation --
restricted stock.............. (2,410) -- --
Capital in excess of par
value......................... 77,467 74,027 73,955
Retained earnings............... 7,752 3,766 1,103
------------- ------------ ------------
Total stockholders'
equity..................... 82,882 77,864 75,129
------------- ------------ ------------
Total liabilities and
stockholders' equity.... $ 156,350 $ 118,520 $ 83,867
============= ============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.

F-3
<PAGE>
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
-------------------- -------------------------------
1997 1996 1996 1995 1994
--------- --------- --------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales............... $ 29,578 $ 18,578 $ 25,764 $ 23,210 $ 13,948
Interest and other.............. 1,162 537 946 627 171
--------- --------- --------- --------- ---------
Total revenues............. 30,740 19,115 26,710 23,837 14,119
--------- --------- --------- --------- ---------
Costs and expenses:
Lease operating expenses........ 6,235 5,646 7,562 6,732 4,042
Depreciation, depletion and
amortization.................. 11,288 7,697 9,832 10,376 6,049
General and administrative...... 3,263 2,352 3,495 3,880 3,717
Interest........................ 945 184 313 1,794 624
--------- --------- --------- --------- ---------
Total costs and expenses... 21,731 15,879 21,202 22,782 14,432
--------- --------- --------- --------- ---------
Income (loss) from operations........ 9,009 3,236 5,508 1,055 (313)
Income tax expense (benefit).... 2,926 -- 50 -- (200)
--------- --------- --------- --------- ---------
Net income (loss).................... 6,083 3,236 5,458 1,055 (113)
Preferred stock dividends............ 2,097 2,097 2,795 256 --
--------- --------- --------- --------- ---------
Net income (loss) available to common
shares............................. $ 3,986 $ 1,139 $ 2,663 $ 799 $ (113)
========= ========= ========= ========= =========
Net income (loss) per common share:
Primary......................... $ 0.63 $ 0.20 $ 0.45 $ 0.14 $ (0.03)
========= ========= ========= ========= =========
Assuming full dilution.......... $ 0.62 $ 0.20 $ 0.43 $ 0.14 $ (0.03)
========= ========= ========= ========= =========
Shares used in computing net income
(loss) per common share:
Primary......................... 6,332 5,755 5,952 5,755 4,346
========= ========= ========= ========= =========
Assuming full dilution.......... 6,440 5,755 6,135 5,755 4,346
========= ========= ========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.

F-4
<PAGE>
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
UNEARNED
COMPENSATION CAPITAL IN
CAPITAL PREFERRED COMMON RESTRICTED EXCESS OF RETAINED
ACCOUNTS STOCK STOCK STOCK PAR VALUES EARNINGS
--------- ---------- ------- ------------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1993.......... $ 27,170 $ -- $ -- $ -- $ -- $ --
Pre consolidation income (loss)...... (417) -- -- -- -- --
Distributions........................ (1,191) -- -- -- -- --
Consolidation (Note 1)............... (25,562) -- 58 -- 43,069 --
Post consolidation income............ -- -- -- -- -- 304
--------- ---------- ------- ------------- ---------- ---------
Balances, December 31, 1994.......... -- -- 58 -- 43,069 304
Net income........................... -- -- -- -- -- 1,055
Sale of preferred stock (Note 11).... -- 13 -- -- 30,886 --
Preferred stock dividends............ -- -- -- -- -- (256)
--------- ---------- ------- ------------- ---------- ---------
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 (Unaudited)............... -- -- -- -- -- 6,083
Preferred stock dividends
(Unaudited)........................ -- -- -- -- -- (2,097)
Shares issued pursuant to employee
benefit plan (Unaudited)........... -- -- -- -- 289 --
Restricted stock issued to officers
(Unaudited)........................ -- -- 2 (3,153) 3,151 --
Unearned compensation -- restricted
stock -- (Unaudited)............... -- -- -- 743 -- --
--------- ---------- ------- ------------- ---------- ---------
Balances, September 30, 1997
(Unaudited)........................ $ -- $ 13 $ 60 $ (2,410) $ 77,467 $ 7,752
========= ========== ======= ============= ========== =========
</TABLE>
The accompanying notes are an integral part of these financial statements.

F-5
<PAGE>
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
---------------------- ----------------------------------
1997 1996 1996 1995 1994
---------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss).................. $ 6,083 $ 3,236 $ 5,458 $ 1,055 $ (113)
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depreciation, depletion and
amortization............... 11,607 7,913 10,131 10,600 6,328
Amortization of deferred
costs...................... 321 201 114 133 88
Deferred income tax expense
(benefit).................. 2,926 -- 50 -- (200)
Noncash compensation related
to stock plans............. 973 -- 72 -- --
Changes in current assets and
liabilities:
Accounts receivable...... 3,040 (72) (4,332) 566 565
Other current assets..... (222) 89 (278) (217) (8)
Current liabilities...... (3,924) 5,728 4,049 (2,570) (1,242)
Change in gas balancing
receivable................. 414 184 (41) 115 (148)
Change in gas balancing
payable.................... (77) (79) (42) (127) 210
Change in other long-term
liabilities................ 185 (25) (28) (42) (43)
Change in other assets, net... (1,018) (53) (830) (61) (90)
---------- ---------- ---------- ---------- ----------
Cash provided by operating
activities................. 20,308 17,122 14,323 9,452 5,347
---------- ---------- ---------- ---------- ----------
Cash flows from investing activities:
Capital expenditures............... (61,034) (20,402) (37,637) (24,323) (10,420)
Equity issued to purchase CN cash
(Note 4)......................... -- -- -- -- 3,989
Cash proceeds from sale of mineral
interests........................ 4,405 528 1,574 86 8
---------- ---------- ---------- ---------- ----------
Cash used in investing
activities....................... (56,629) (19,874) (36,063) (24,237) (6,423)
---------- ---------- ---------- ---------- ----------
Cash flows from financing activities:
Equity issued by conversion of
stock options.................... 60 -- -- -- --
Payments on debt................... (18,500) -- (25,850) (25,134) (20,627)
Proceeds from debt issuance........ 54,500 8,850 50,000 6,000 25,734
Dividends/distributions paid....... -- -- -- -- (1,191)
Sale of preferred stock............ -- -- -- 30,899 --
Increase in accrued preferred stock
dividends payable................ -- 443 443 256 --
Dividends on preferred stock....... (2,097) (2,097) (2,795) (256) --
Change in accrued liabilities for
capital expenditures............. 628 -- 3,346 -- --
---------- ---------- ---------- ---------- ----------
Cash provided by financing
activities....................... 34,591 7,196 25,144 11,765 3,916
---------- ---------- ---------- ---------- ----------
Net increase (decrease) in cash and cash
equivalents........................... (1,730) 4,444 3,404 (3,020) 2,840
Cash and cash equivalents:
Balance, beginning of period....... 7,669 4,265 4,265 7,285 4,445
---------- ---------- ---------- ---------- ----------
Balance, end of period............. $ 5,939 $ 8,709 $ 7,669 $ 4,265 $ 7,285
========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.

F-6
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION WITH RESPECT TO SEPTEMBER 30, 1997 AND 1996 IS UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION

Callon Petroleum Company, formerly Callon Petroleum Holding 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 to combine the businesses
and properties of Callon Consolidated Partners, L.P. ("CCP"), Callon Petroleum
Operating Company ("CPOC") and CN Resources ("CN"), directly or indirectly,
with the Company. CPOC was the general partner of CCP, and CN was a general
partnership between CPOC and NOCO Enterprises, L. P. ("NOCO"), a limited
partnership owned by private investors (CPOC, CCP and CN are referred to
collectively as the "Constituent Entities"). The combination of the businesses
and properties of the Constituent Entities with the Company was effected in
three simultaneous transactions on September 16, 1994 (collectively, the
"Consolidation"):

(i) CCP was merged (the "Merger") into the Company and each unit of
limited partner interest in CCP ("Units") was converted into the right to
receive one-third of a share of Common Stock of the Company ("Common
Stock"). Subject to compliance with certain requirements, any holder of
less than 100 Units could elect to receive, in lieu of shares of Common
Stock, $4.50 in cash per Unit owned. CCP unitholders received 1,877,493
shares of Common Stock of the Company.

(ii) Holders of capital stock of CPOC exchanged such capital stock
for an aggregate of 1,892,278 shares of Common Stock of the Company,
resulting in CPOC becoming a wholly owned subsidiary of the Company (the
"Share Exchange").

(iii) NOCO exchanged its partner interest for 1,984,758 shares of
Common Stock of the Company, resulting in CN becoming directly and
indirectly wholly owned by the Company (the "CN Exchange"). See Note 4.

As a result of the Consolidation, all of the businesses and properties of
the Constituent Entities are owned (directly or indirectly) by the Company, and
the former stockholders of CPOC, partners of CCP and NOCO have become
stockholders of the Company. Certain registration rights were granted to the
holders of the capital stock of CPOC and NOCO. 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 and
offshore Gulf of Mexico.

BASIS OF PRESENTATION

The accompanying Consolidated Financial Statements of the Company reflect
the combination of CPOC, CCP, and CPOC's interest in CN as a reorganization of
entities under common control (accounted for similar to a "pooling of
interest"). NOCO's interest in CN was recorded as a purchase effective at the
date of the Consolidation (September 16, 1994), thus amounts related to the CN
Exchange are included from the date of the purchase for the periods presented in
the Consolidated Financial Statements. CPOC made no direct investment in CN,
therefore the inclusion of 100% of the assets and liabilities of CN in the
Consolidated Balance Sheet, as of the purchase date, are attributable to NOCO's
interest in CN. Because no revenues or expenses, as of the date of the
Consolidation, were attributable to CPOC's interest in CN until NOCO had
received a preferential return on its investment, all of the revenues and
expenses of CN through September 16, 1994, are also attributable to NOCO. See
Note 4 for pro forma information.

F-7
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION AND REPORTING

The Consolidated Financial Statements include the accounts of the Company,
and its subsidiary, CPOC. CPOC also has subsidiaries which are Callon Offshore
Production, Inc., Mississippi Marketing, Inc. and Callon Exploration Company.
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 March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121 ("FAS 121"), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of".
FAS 121 was adopted by the Company on January 1, 1996. The effect of adopting
FAS 121 was not material to the Company's financial position or results of
operations.

In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123 ("FAS 123"), "Accounting for
Stock-Based Compensation", effective for the Company at December 31, 1996.
Under FAS 123, companies can either record expenses based on the fair value of
stock-based compensation upon issuance or elect to remain under the current
"APB Opinion No. 25" method, whereby no compensation cost is recognized upon
grant, and make disclosures as if FAS 123 had been applied. The Company will
continue to account for its stock-based compensation plans under APB Opinion No.
25. See Note 10.

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 is effective for fiscal
years beginning after December 15, 1997. The Company intends to comply with the
provisions of FAS 130.

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 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

F-8
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 cost of unevaluated properties (the full cost ceiling amount), then
such excess is charged to expense during the period in which the excess occurs.

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 September 30, 1997, December 31,
1996 and 1995, 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 facilities is provided using the straight-line method over a 27
year estimated life.

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.

RESERVE FOR DOUBTFUL ACCOUNTS

The balance in the reserve for doubtful accounts included in accounts
receivable is $302,000, $393,000 and $481,000 at September 30, 1997, December
31, 1996 and 1995 respectively. Net charge offs were $88,000 and $181,000 in
1996 and 1994 and net recoveries were $2,000 in 1995. There were no provisions
to expense in the three year period ended December 31, 1996 or the nine months
ended September 30, 1997. Net charge offs were $91,000 and $88,000 for the nine
months ended September 30, 1997 and 1996, respectively.

STATEMENTS OF CASH FLOWS

For purposes of the Consolidated Statements of Cash Flows, 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, 1996. During the years ended December 31, 1996, 1995 and 1994, the Company
made cash payments of $250,807, $1,910,000 and $377,000, respectively, for
interest charged on its indebtedness, and $2,538,000 for the nine months ended
September 30, 1997.

PER SHARE AMOUNTS

Per share amounts are calculated on a weighted average basis using common
shares issued and outstanding, adjusted for the effect of stock options
considered common stock equivalents computed using the treasury stock method.

The conversion of preferred stock was not included in any current year or
prior calculations due to their antidilutive effect on fully diluted earnings
per share.

F-9
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In February 1997, the Financial Accounting Standards Board issued Statement
No. 128 ("FAS 128"), "Earnings Per Share", which simplifies the computation
of earnings per share. FAS 128 is effective for financial statements issued for
periods ending after December 15, 1997 and requires restatement for all prior
period earnings per share data presented. Accordingly, basic earnings per share
and diluted earnings per share calculated in accordance with FAS 128 were $0.63
and $0.62 per share, respectively, for the first nine months of 1997 and $0.20
and $0.20 per share, respectively, for the first nine months of 1996.

Also in early 1997, the Financial Accounting Standards Board issued
Statement No. 129 ("FAS 129"). "Disclosure of Information about Capital
Structure" effective for financial statements issued for periods ending after
December 15, 1997. The Company believes it is in compliance with the provisions
of this statement.

FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value of cash, cash equivalents, accounts receivable, accounts payable
and long-term debt approximate book value at September 30, 1997 and December 31,
1996. Fair value of long-term debt (specifically the senior subordinated notes)
is based on quoted market value.

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.
Accordingly, the Company has recorded a deferred tax asset at December 31, 1996,
1995 and 1994 as follows:

DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
(IN THOUSANDS)
Federal net operating loss
carryforward.......................... $ 3,441 $ 3,563 $ 2,072
Statutory depletion carryforward........ 4,089 3,987 4,085
Temporary differences:
Oil and gas properties............. (680) 874 2,817
Pipeline and other facilities...... (2,316) (1,880) (1,953)
Non-oil and gas property........... (20) 23 28
Other.............................. 898 655 724
--------- --------- ---------
Total tax asset......................... 5,412 7,222 7,773
Valuation allowance..................... -- (1,760) (2,311)
--------- --------- ---------
Net tax asset........................... $ 5,412 $ 5,462 $ 5,462
========= ========= =========

At December 31, 1996, the Company had, for tax reporting purposes,
operating loss carryforwards ("NOL") of $9.8 million which expire in 2000
through 2011. Approximately $4.7 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.

F-10
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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:

DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
(IN THOUSANDS)
Computed expense (benefit) at the
expected statutory rate............ $ 1,910 $ 369 $ (110)
Change in valuation allowance........ (1,760) (551) (94)
Other................................ (100) 182 4
--------- --------- ---------
Income tax expense (benefit)......... $ 50 $ -- $ (200)
========= ========= =========

4. ACQUISITIONS

On September 14, 1994, (with an effective date of September 16, 1994) the
unitholders of CCP, stockholders of CPOC, and the partners of CN completed the
Consolidation as described in Note 1. Net assets purchased (excluding cash of
$3,989,000) was $13,847,000 of which oil and gas property, including pipeline
facilities, and debt amounted to $24,506,000 and $11,436,000, respectively. Such
amounts represent non-cash transactions and therefore are not included in the
Consolidated Statements of Cash Flows.

On December 29, 1995, CPOC purchased a 66.67% working interest in
Chandeleur Block 40 (the "CB 40 Acquisition") from Amerada Hess Corporation
and, in a simultaneous transaction under a pre-existing agreement, sold
one-third of the acquired interest to an industry partner. The Company's net
purchase price of $6 million was funded from existing cash on hand.

The following information represents unaudited pro forma results of the
Company for the years ended December 31, 1995 and 1994 and includes both the
purchase of CN and the CB 40 Acquisition, presented as if the purchase of CN had
occurred at the beginning of 1994 and the CB 40 Acquisition presented as if it
had occurred at the beginning of 1995 and 1994.

PRO FORMA
(UNAUDITED)
--------------------
1995 1994
--------- ---------
(IN THOUSANDS,
EXCEPT
PER SHARE AMOUNTS)
Total revenues....................... $ 25,207 $ 29,132
Net income before cumulative effect
of change in accounting
principle.......................... $ 804 $ 3,703
Net income per common share.......... $ 0.14 $ 0.64
Weighted average shares
outstanding........................ 5,755 5,755

Pro forma shares outstanding used in the above calculations include shares
of the Company issued as a result of the Merger of CCP and the Share Exchange in
addition to the shares of the Company issued in the CN Exchange.

The Company, together with an industry partner, was the high bidder on 12
offshore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157, held
April 24, 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 $11.4 million.

On September 25, 1996, the Company and the same industry partner submitted
bids and were awarded six additional offshore leases at the OCS Lease Sale #161,
held in New Orleans, Louisiana by the MMS. The Company's share of the costs was
$3.8 million. The Company owns a 25% working interest in the leases.

F-11
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On June 26, 1997 the Company purchased an 18.8% working interest in Mobile
Area Blocks 863 and 907 and a 35% working interest in Mobile Area Block 908 from
Elf Exploration, Inc. The Company's net purchase price of approximately $11.8
million was funded from the Company's credit facility.

In October 1997, the Company agreed to purchase 61% of Chevron U.S.A.
Inc.'s interest in the Mobile Block 864 Area for $21 million, effective July 1,
1997. The acquisition closed November 7, 1997 for a net acquisition cost of
$18.8 million and was funded from the Company's Credit Facility.

5. LONG-TERM DEBT

Long-term Debt consisted of the following at:

DECEMBER 31,
SEPTEMBER 30, --------------------
1997 1996 1995
------------- --------- ---------
(UNAUDITED)

(IN THOUSANDS)
Credit Facility...................... $ 100 $ 100 $ 100
10% Senior Subordinated Notes........ 24,150 24,150 --
10.125% Senior Subordinated Notes.... 36,000 -- --
Less current portion............ -- -- --
------------- --------- ---------
$60,250 $ 24,250 $ 100
============= ========= =========

Effective October 31, 1996, the Company entered into a new Credit Facility
with Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. The Credit Facility provides for borrowings of a maximum of the
lesser of $50 million or a $30 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 either the
lender's prime rate or the lender's prime rate plus 0.50%. The Company, at its
option, may fix the interest rate on all or a portion of the outstanding
principal balance at either 1.00% or 1.375% above a defined "Eurodollar" rate,
depending upon the percentage of the unused portion of the Borrowing Base, for
periods of up to six months. The weighted average interest rate for the total
debt outstanding at September 30, 1997 and December 31, 1996 was 8.50% and
8.25%, 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 $36,000,000 of 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 to the Company, after costs of the transaction,
were used to repay the outstanding balance on Callon's Credit Facility and will
fund a portion of the remaining capital expenditure budget. Pursuant to a
Registration Agreement, on November 10, 1997,

F-12
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

these Series A 10.125% Notes were exchanged for $36 million aggregate principal
amount of the Company's 10.125% Series B Senior Subordinated Notes due 2002 that
have been registered under the Securities Act.

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. This Company is in
compliance with these covenants at September 30, 1997.

6. HEDGING CONTRACTS

The Company hedges with third parties certain of its crude oil and natural
gas production in various swap agreement contracts. The contracts are tied to
published market prices for crude oil and natural gas and are settled monthly
based on the differences between contract prices and the average defined market
price for that month applied to the related contract volume. The Company had no
open forward sales position related to this type of contract as of December 31,
1996 and September 30, 1997.

At September 30, 1997 the Company had outstanding a call option for 250,000
Mcf per month from December 1997 through February 1998 at $3.00 per Mcf.

As of December 31, 1996, the Company has 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 1997 are
for average oil volumes of 15,000 barrels per month at (on average) a ceiling
price of $23.33 and floor of $18.00 and for average gas volumes of 583,000 Mcf
per month in the first quarter of 1997 at (on average) a ceiling price of $3.36
and floor of $2.88. As of September 30, 1997, oil contracts averaged volumes of
10,000 barrels per month at (on average) a ceiling of $24.00 and a floor of
$18.00 through 1997. Gas contracts included gas volumes of 700,000 Mcf per month
at (on average) a ceiling price of $3.03 and a floor of $2.31 through March
1998.

During 1994, the Company recognized revenue under swap agreements of
$1,227,000 and $1,724,000 on Historical and Pro forma basis respectively, and
$2,466,000 for the twelve months ended December 31, 1995. The Company recognized
a reduction in revenue of $2,757,195 for the year ended December 31, 1996 under
all contracts. During the first nine months of 1997, the Company recognized an
increase in revenues of $328,975 for all contracts.

The calculation of the fair market value of the outstanding contracts as of
December 31, 1996 indicates a $308,400 market value benefit to the Company based
on market prices at that date. As of September 30, 1997 the calculation of the
fair market value of the outstanding contracts indicates a $646,008 market value
liability to the Company based on market prices at that date.

7. COMMITMENTS AND CONTINGENCIES

As described in Note 9, abandonment trusts (the "Trusts") have been
established for future abandonment obligations of those oil and gas properties
of the Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses in
excess of the Trusts' balances. As of December 31, 1996, total estimated site
restoration, dismantlement and abandonment costs were approximately $23,000,000,
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.

Also, as part of the Consolidation, the Company entered into Registration
Rights Agreements whereby the former stockholders of CPOC and NOCO 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

F-13
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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>
NINE MONTHS
ENDED YEAR ENDED DECEMBER 31,
SEPTEMBER 30, ----------------------------------
1997 1996 1995 1994
------------- ---------- ---------- ----------
(UNAUDITED) (IN THOUSANDS)
<S> <C> <C> <C> <C>
Capitalized costs incurred:
Evaluated Properties --
Beginning of period balance..... $ 322,970 $ 304,737 $ 285,976 $ 260,971
Property acquisition costs...... 32,341 2,999 14,017 23,037
Exploration costs............... 11,831 8,732 785 798
Development costs............... 11,376 8,076 4,045 1,178
Sale of mineral interest........ (4,405) (1,574) (86) (8)
------------- ---------- ---------- ----------
End of period balance........... $ 374,113 $ 322,970 $ 304,737 $ 285,976
============= ========== ========== ==========
Unevaluated Properties --
Beginning of period balance..... $ 26,235 $ 10,171 $ 4,919 $ 955
Additions, net of transfers to
evaluated... 3,169 15,714 5,252 3,964
Capitalized interest............ 1,550 350 -- --
------------- ---------- ---------- ----------
End of period balance........... $ 30,954 $ 26,235 $ 10,171 $ 4,919
============= ========== ========== ==========
Accumulated depreciation, depletion
and amortization --
Beginning of period balance..... $ 266,716 $ 257,143 $ 246,975 $ 240,926
Provision charged to expense.... 11,055 9,573 10,168 6,049
------------- ---------- ---------- ----------
End of period balance........... $ 277,771 $ 266,716 $ 257,143 $ 246,975
============= ========== ========== ==========
</TABLE>
Depreciation, depletion and amortization per unit-of-production (equivalent
barrel of oil) amounted to $5.87, $5.95, and $5.80 for the years ended December
31, 1996, 1995 and 1994, respectively, and $5.77 and $6.02 for the nine months
ended September 30, 1997 and 1996, respectively.

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 price
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

F-14
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 September 30, 1997, December 31, 1996 and
1995 the Trusts' assets (all cash and investments) totaled $18,800,000,
$18,200,000 and $16,100,000, respectively, all of which will be available to the
Company to pay its portion, as working interest owner, of the restoration,
dismantlement and abandonment costs discussed at Note 7.

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

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

10. EMPLOYEE BENEFIT PLANS

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

o 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 $241,000,
$176,000 and $154,000 in the years 1996, 1995 and 1994, respectively.

o 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 are outstanding and all such options could
be exercised as of December 31, 1996. These options have an expiration
date 10 years from date of grant.

o 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

F-15
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

same types of awards as the 1994 Plan and is limited to a maximum of
900,000 shares of common stock that may be subject to outstanding
awards. The Company granted stock options to purchase an aggregate
530,000 shares of Common Stock under the plan, subject to stockholder
approval of the 1996 Plan. All of such options were granted at an
exercise price of $12 per share, the fair market value of the Common
Stock on the date of grant. Terms of the plan for 450,000 options
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 (see Note 2). Had compensation cost for these 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:

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
Net income (loss):
As Reported........................ $ 2,663 $ 799 $ (113)
Pro Forma.......................... 2,411 677 (113)
Primary per share:
As Reported........................ 0.45 0.14 (0.03)
Pro Forma.......................... 0.41 0.12 (0.03)
Fully diluted per share:
As Reported........................ 0.43 0.14 (0.03)
Pro Forma.......................... 0.39 0.12 (0.03)

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 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, 1996, 1995 and 1994 and changes during the years then ended is presented in
the table and narrative below:
<TABLE>
<CAPTION>
1996 1995 1994
-------------------- ------------------- -------------------
WTD AVG WTD AVG WTD AVG
EX EX EX
SHARES PRICE SHARES PRICE SHARES PRICE
--------- ------- -------- ------- -------- -------
<S> <C> <C> <C> <C> <C>
Outstanding, beginning of year.......... 490,000 $10.01 460,000 $10.00 -- $ --
Granted............................ 550,000 12.06 30,000 10.08 460,000 10.00
Exercised.......................... -- -- -- -- -- --
Forfeited.......................... (10,000) 10.00 -- -- -- --
Expired............................ -- -- -- -- -- --
--------- ------- -------- ------- -------- -------
Outstanding, end of year................ 1,030,000 $11.10 490,000 $10.01 460,000 $10.00
========= ======= ======== ======= ======== =======
Exercisable, end of year................ 500,000 $10.16 490,000 $10.01 -- $ --
========= ======= ======== ======= ======== =======
Weighted average fair value of options
granted............................... $ 4.96 $ 4.05 $ 4.53
========= ======== ========
</TABLE>
F-16
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The options outstanding at December 31, 1996 have exercise prices ranging
from $9.75 to $13.75 with a remaining weighted average contractual life of 5.98
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 1996, 1995 and 1994.

WEIGHTED AVERAGE ASSUMPTIONS

DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
Risk-free interest rate................. 6.5% 6.6% 6.0%
Expected life (years)................... 4.9 5.0 5.0
Expected volatility..................... 34.7% 32.0% 41.3%
Expected dividends...................... -- -- --

The Company also 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
is being amortized as compensation expense on a straight-line basis over the
vesting period. Approximately $208,000 of compensation cost was charged to
expense in 1996 related to the restricted shares granted. An additional 25,000
shares was issued under the 1994 Plan in 1997.

The Company has no other formal benefit plans.

F-17
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

11. PREFERRED STOCK

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.

12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)

The Company's proved oil and gas reserves at December 31, 1996, 1995 and
1994 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.

F-18
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

YEAR ENDED DECEMBER 31,
-------------------------------
1996 1995 1994
--------- --------- ---------
Proved developed and undeveloped
reserves:
Crude Oil (MBbls):
Beginning of period............. 4,766 4,424 2,842
Revisions to previous
estimates..................... (50) (441) (303)
Purchase of reserves in place... -- 1,363 2,245
Sales of reserves in place...... (312) (2) (3)
Extensions and discoveries...... -- 16 7
Production...................... (585) (594) (364)
--------- --------- ---------
End of period................... 3,819 4,766 4,424
========= ========= =========
Natural Gas (MMcf):
Beginning of period............. 29,667 24,102 14,167
Revisions to previous
estimates..................... (1,688) (976) (2,793)
Purchase of reserves in place... 7,391 12,985 16,757
Sales of reserves in place...... (228) (22) (39)
Extensions and discoveries...... 21,551 271 85
Production...................... (6,269) (6,693) (4,075)
--------- --------- ---------
End of period................... 50,424 29,667 24,102
========= ========= =========
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period............. 3,890 3,309 2,084
========= ========= =========
End of period................... 3,385 3,890 3,309
========= ========= =========
Natural Gas (MMcf):
Beginning of period............. 20,408 20,582 11,366
========= ========= =========
End of period................... 49,491 20,408 20,582
========= ========= =========

F-19
<PAGE>
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. In 1995 and 1994, no future income taxes were provided on the future
net inflows as tax credits (including carryovers) and other permanent
differences were expected to be higher than the estimated future income taxes
calculated using the appropriate statutory rates.

The resulting net future cash flows have been discounted to their present
values based on a 10% annual discount factor.

STANDARDIZED MEASURE

YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
(IN THOUSANDS)
Future cash inflows.................. $ 285,727 $ 157,240 $ 115,659
Future costs --
Production...................... (59,584) (50,236) (43,579)
Development and net
abandonment................... (9,989) (11,274) (12,603)
---------- ---------- ----------
Future net inflows before income
taxes.............................. 216,154 95,730 59,477
Future income taxes.................. (49,438) -- --
---------- ---------- ----------
Future net cash flows................ 166,716 95,730 59,477
10% discount factor.................. (36,547) (31,966) (18,094)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows.............. $ 130,169 $ 63,764 $ 41,383
========== ========== ==========

CHANGES IN STANDARDIZED MEASURE

YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
(IN THOUSANDS)
Standardized measure -- beginning of
period............................. $ 63,764 $ 41,383 $ 22,554
Sales and transfers, net of
production costs................... (18,202) (12,477) (9,815)
Net change in sales and transfer
prices, net of production costs.... 32,268 11,519 1,368
Exchange and sale of in place of
reserves........................... (877) (23) (48)
Purchases, extensions, discoveries,
and improved recovery, net of
future production and development
costs.............................. 79,983 28,204 26,376
Revisions of quantity estimates...... (3,907) (4,242) (6,297)
Accretions of discount............... 6,376 2,963 1,488
Net change in income taxes........... (30,000) -- --
Changes in production rates, timing
and other.......................... 764 (3,563) 5,757
---------- ---------- ----------
Standardized measure -- end of
period............................. $ 130,169 $ 63,764 $ 41,383
========== ========== ==========

F-20

<PAGE>
CALLON PETROLEUM COMPANY
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

INTRODUCTION

The following unaudited pro forma financial statements are based on the
historical balance sheet and results of operations of Callon Petroleum Company
after giving pro forma effect to (i) the recent acquisitions described below and
(2) the Offering, as if such acquisitions and the Offering had occurred on
September 30, 1997, and at the beginning of the earliest period presented.

On June 26, 1997, Callon Petroleum Operating Company, a wholly owned
subsidiary of the Company purchased a working interest in the Mobile Area Block
864 Unit from Elf Exploration, Inc. (the "Elf Acquisition") The Company's net
purchase price was $11.8 million.

In October 1997, the Company agreed to purchase 61% of Chevron U.S.A,
Inc.'s interest in the Mobile Block Area (the "Chevron Acquisition") for $21
million effective July 1, 1997. The Chevron Acquisition closed on November 7,
1997 for a net purchase price of $18.8 million.

See Note 1 in the Notes to Pro Forma Consolidated Financial Statements for
the basis of presentation of the above events in the Pro Forma Consolidated
Financial Statements of the Company.

F-21
<PAGE>
CALLON PETROLEUM COMPANY
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET
SEPTEMBER 30, 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
PRO FORMA PRO FORMA
HISTORICAL ADJUSTMENTS AS ADJUSTED
---------- ----------- -----------
<S> <C> <C> <C>
ASSETS
Current assets.......................... $ 16,298 $ 6,412(f) $ 22,710
Net oil and gas properties (full cost
method)............................... 127,296 18,792(f) 146,088
Other assets............................ 12,756 12,756
---------- ----------- -----------
Total assets....................... $ 156,350 $25,204 $ 181,554
========== =========== ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities..................... $ 12,672 $-- $ 12,672
Long-term debt.......................... 60,250 -- 60,250
Other liabilities....................... 546 -- 546
Stockholders' equity.................... 82,882 25,204(f) 108,086
---------- ----------- -----------
Total liabilities and stockholders'
equity........................... $ 156,350 $25,204 $ 181,554
========== =========== ===========
</TABLE>
See Notes to Unaudited Pro Forma Consolidated Financial Statements

F-22
<PAGE>
CALLON PETROLEUM COMPANY
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
HISTORICAL ELF CHEVRON PRO FORMA PRO FORMA
COMPANY ACQUISITION ACQUISITION ADJUSTMENTS AS ADJUSTED
---------- ----------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales............... $ 25,764 $ 4,455(a) $ 8,735(b) $ -- $ 38,954
Interest and other.............. 946 -- -- -- 946
---------- ----------- ------------ ----------- ------------
Total revenues............. 26,710 4,455 8,735 -- 39,900
---------- ----------- ------------ ----------- ------------
Expenses:
Lease operating expenses........ 7,562 245(a) 295(b) -- 8,102
Depreciation, depletion and
amortization.................. 9,832 -- -- 4,912(d) 14,744
General and administrative...... 3,495 -- -- -- 3,495
Interest........................ 313 -- -- 1,548(c) 1,861
---------- ----------- ------------ ----------- ------------
Total costs and expenses... 21,202 245 295 6,460 28,202
---------- ----------- ------------ ----------- ------------
Income from operations............... 5,508 4,210 8,440 (6,460) 11,698
Income tax expense................... 50 -- -- 4,044(e) 4,094
---------- ----------- ------------ ----------- ------------
Net income........................... 5,458 4,210 8,440 (10,504) 7,604
Preferred stock dividends............ 2,795 -- -- -- 2,795
---------- ----------- ------------ ----------- ------------
Net income available to common
shares............................. $ 2,663 $ 4,210 $ 8,440 $ (10,504) $ 4,809
========== =========== ============ =========== ============
Net income per common share:
Primary......................... $ 0.45 $ 0.64
========== ============
Assuming full dilution.......... $ 0.43 $ 0.62
========== ============
Shares used in computing net income
per common share:
Primary......................... 5,952 7,552
========== ============
Assuming full dilution.......... 6,135 7,735
========== ============
</TABLE>
See Notes to Unaudited Pro Forma Consolidated Financial Statements

F-23
<PAGE>
CALLON PETROLEUM COMPANY
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 1997
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
HISTORICAL ELF CHEVRON PRO FORMA PRO FORMA
COMPANY ACQUISITION ACQUISITION ADJUSTMENTS AS ADJUSTED
---------- ----------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales............... $ 29,578 $ 1,813(a) $4,667(b) $-- $ 36,058
Interest and other.............. 1,162 -- -- -- 1,162
---------- ----------- ------------ ----------- ------------
Total revenues............. 30,740 1,813 4,667 -- 37,220
---------- ----------- ------------ ----------- ------------
Expenses:
Lease operating expenses........ 6,235 (69)(a) 53(b) -- 6,219
Depreciation, depletion and
amortization.................. 11,288 -- -- 2,881(d) 14,169
General and administrative...... 3,263 -- -- -- 3,263
Interest........................ 945 -- -- 551(c) 1,496
---------- ----------- ------------ ----------- ------------
Total costs and expenses... 21,731 (69) 53 3,432 25,147
---------- ----------- ------------ ----------- ------------
Income from operations............... 9,009 1,882 4,614 (3,432) 12,073
Income tax expense................... 2,926 -- -- 1,299(e) 4,225
---------- ----------- ------------ ----------- ------------
Net income........................... 6,083 1,882 4,614 (4,731) 7,848
Preferred stock dividends............ 2,097 -- -- -- 2,097
---------- ----------- ------------ ----------- ------------
Net income available to common
shares............................. $ 3,986 $ 1,882 $4,614 $(4,731) $ 5,751
========== =========== ============ =========== ============
Net income per common share:
Primary......................... $ 0.63 $ 0.72
========== ============
Assuming full dilution.......... $ 0.62 $ 0.71
========== ============
Shares used in computing net income
per common share:
Primary......................... 6,332 7,932
========== ============
Assuming full dilution.......... 6,440 11,030
========== ============
</TABLE>
See Notes to Unaudited Pro Forma Consolidated Financial Statements

F-24
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

On June 26, 1997, Callon Petroleum Operating Company, a wholly owned
subsidiary of Callon Petroleum Company (the "Company"), purchased an 18.8%
working interest in the Mobile Area Block 864 Unit from Elf Exploration, Inc.
(the "Elf Acquisition"). The Company's net purchase price was $11.8 million.

In October 1997, the Company agreed to purchase 61% of Chevron U.S.A.
Inc.'s interest in the Mobile Block 864 Area (the "Chevron Acquisition") for
$21 million effective July 1, 1997. The Chevron Acquisition closed on November
7, 1997 for a net purchase price of $18.8 million. The Company utilized
borrowings under its existing Credit Facility to complete the Chevron
Acquisition.

The accompanying Pro Forma Consolidated Statements of Operations of the
Company for the year ended December 31, 1996 and the nine months ended September
30, 1997 give effect to the Elf Acquisition, the Chevron Acquisition and the
sale of Common Stock offered hereby and the application of the proceeds
therefrom, as if the transactions occurred at the beginning of the earliest
period presented.

The accompanying Pro Forma Consolidated Balance Sheet at September 30, 1997
gives effect to the Chevron Acquisition and the sale of the Common Stock offered
hereby and the application of the proceeds therefrom, as if the transactions
occurred on September 30, 1997.

The Pro Forma Consolidated Statements of Operations and Balance Sheet are
based on the assumptions set forth in the notes to such statements. Such pro
forma information should be read in conjunction with the related financial
information of the Company and is not necessarily indicative of the results
which would actually have occurred had the transaction been in effect on the
date or for the period indicated or which may occur in the future.

2. PRO FORMA ADJUSTMENTS

Pro Forma entries necessary to adjust the historical financial statements
of the Company are as follows:

(a) To reflect the Elf Acquisition and the related results of operations
as described in Note 1.

(b) To reflect the Chevron Acquisition and the related results of
operations as described in Note 1.

(c) To reflect an increase in interest expense related to borrowing made
to complete the Elf Acquisition and the Chevron Acquisition as if the
transactions, less the effect of the net proceeds of the sale of the Common
Stock offered hereby, had occurred at the beginning of the year ended December
31, 1996. The estimated interest rate used was 8.5%. A one-eighth change in this
estimated rate would have the effect of $23,000 for the year ended December 31,
1996 and $8,000 for the nine months ended September 30, 1997.

(d) To adjust the provision for depreciation, depletion and amortization
of the combined full cost pool based on the purchase of the Elf Acquisition and
the Chevron Acquisition as described in Note 1.

(e) To record a provision for Federal income taxes at a corporate
statutory rate of 35% on pro forma income as a result of the acquisitions
described in Note 1.

(f) Reflects the use of the proceeds to complete the sale of the Common
Stock as a result of the Offering and the Chevron Acquisition as if both
occurred at September 30, 1997.

F-25

<PAGE>
REPORT OF INDEPENDENT AUDITORS

Stockholders and Board of Directors
Callon Petroleum Company

We have audited the accompanying statement of revenues and direct operating
expenses of the working interest in Mobile Area Block 864 Unit (the
"Property") acquired by Callon Petroleum Operating Company (the "Company"),
a wholly owned subsidiary of Callon Petroleum Company, from Elf Exploration,
Inc. (see Note 1 to the accompanying statement) for the year ended December 31,
1996. This statement is the responsibility of the Company's management. Our
responsibility is to express an opinion on this statement based on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of revenues and direct
operating expenses is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statement of revenues and direct operating expenses. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall statement presentation. We believe
that our audit provides a reasonable basis for our opinion.

The accompanying statement of revenues and direct operating expenses was
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission and is not intended to be a complete
presentation of revenues and expenses of the Property.

In our opinion, the statement of revenues and direct operating expenses
referred to above presents fairly, in all material respects, the revenues and
direct operating expenses of the Property for the year ended December 31, 1996,
in conformity with generally accepted accounting principles.

ERNST & YOUNG LLP

July 24, 1997
Houston, Texas

F-26
<PAGE>
CALLON PETROLEUM COMPANY
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY

SIX MONTHS
YEAR ENDED ENDED
DECEMBER 31, 1996 JUNE 30, 1997
----------------- --------------
(UNAUDITED)

(IN THOUSANDS)
Oil and gas revenues................. $ 4,455 $1,813
Direct operating expenses............ 245 (69)
-------- --------------
Revenues in excess of direct
operating expenses................... $ 4,210 $1,882
======== ==============

See accompanying notes

F-27
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING
EXPENSES OF THE PROPERTY
DECEMBER 31, 1996

1. BASIS OF PRESENTATION

Callon Petroleum Operating Company (the "Company"), a wholly owned
subsidiary of Callon Petroleum Company, acquired a working interest in Mobile
Area Block 864 Unit (the "Property") from Elf Exploration, Inc. (the
"Seller"). The closing date of the acquisition was June 26, 1997, and the net
purchase price was $11.8 million.

The accompanying statement of revenues and direct operating expenses, which
is prepared on the accrual basis of accounting, related only to the working
interest in the producing oil and gas property acquired and may not be
representative of future operations. The statement includes revenues and direct
operating expenses, including production and ad valorem taxes, for the entire
period presented. The statement does not include federal and state income taxes,
interest, depletion, depreciation and amortization, or general and
administrative expenses because such amounts would not be indicative of those
expenses which would be incurred by the Company. Presentation of complete
historical financial statements for the year ended December 31, 1996 and the six
months ended June 30, 1997 is not practicable because the Property was not
accounted for as a separate entity; therefore, such statements are not
available.

Revenues in the accompanying statements of revenues and direct operating
expenses are recognized on the entitlement method.

The preparation of the statement of revenues and direct operating expenses
in conformity with generally accepted accounting principles requires management
to make estimates and assumptions that affect the amounts reported in the
statement and accompanying notes. Actual results could differ from those
estimates.

The unaudited statement of revenues and direct operating expenses for the
six-month period ended June 30, 1997, in the opinion of management, was prepared
on a basis consistent with the audited statement of revenues and direct
operating expenses and includes all adjustments necessary to present fairly the
results of the period.

2. SUPPLEMENTAL INFORMATION ON OIL AND GAS RESERVES (UNAUDITED)

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing of
development expenditures. Therefore, actual production, revenues, and
development and operating expenses may not occur as estimated. The reserve data
are estimates only, are subject to many uncertainties, and are based on data
gained from production histories and on assumptions as to geologic formations
and other matters. Actual quantities may differ materially from the amounts
estimated.

F-28
<PAGE>
CALLON PETROLEUM COMPANY
NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING
EXPENSES OF THE PROPERTY -- (CONTINUED)

The following reserve data, prepared by the Company, represents estimates
of proved natural gas reserves of the Property, which is located in the United
States. There are no oil reserves associated with the Property.

1996
---------
NATURAL GAS (MMCF)
Proved reserves:
Beginning of period...... 11,842
Production............... 1,795
---------
End of period............ 10,047
=========
Proved developed reserves:
Beginning of period...... 11,842
End of period............ 10,047

The estimated standardized measure of discounted future net cash flows
relating to proved reserves of the Property at December 31, 1996 is shown below
and should not be construed as the current market value. No deductions were made
for general overhead, depletion, depreciation and amortization, debt service, or
any indirect costs. Since the Property is not a separate tax-paying entity, the
standardized measure of discounted future net cash flows for the Property is
presented before deduction of income taxes.

1996
--------------
(IN THOUSANDS)
Future cash inflows........... $ 38,680
Future production costs....... (3,241)
--------------
Future net cash flows before
income taxes................ 35,439
10% annual discount for
estimated timing of cash
flows....................... (10,186)
--------------
Standardized measure of
discounted future net cash
flows relating to proved
reserves before income
taxes....................... $ 25,253
==============

Changes in the standardized measure of discounted future net cash flows
relating to proved reserves of the Property are shown below.

1996
--------------
(IN THOUSANDS)
Balances at beginning of
period...................... $ 16,643
Increase (decrease) in
discounted future net cash
flows:
Sales and transfers of
natural gas produced,
net of production
costs.................. (4,210)
Accretion of discount.... 1,419
Net change in sales price
and production costs... 11,401
--------------
Balance at end of period...... $ 25,253
==============

The weighted average prices of natural gas at December 31, 1995 and 1996
used in the calculation of the standardized measure of discounted future net
cash flows were $2.28 and $3.85 per Mcf, respectively.

F-29

<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders
of Callon Petroleum Company

We have audited the accompanying statement of revenues and direct operating
expenses of 61% of Chevron U.S.A. Inc.'s working interest in Mobile 864 Unit
Outer Continental Shelf (the "Property") acquired by Callon Petroleum
Operating Company (the "Company"), a wholly owned subsidiary of Callon
Petroleum Company, for each of the three years in the period ended December 31,
1996. This statement is the responsibility of the Company's management. Our
responsibility is to express an opinion on this statement based on our audit.

We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the statement of revenues and direct
operating expenses is free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the statement of revenues and direct operating expenses. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the statement of
revenues and direct operating expenses. We believe that our audit provides a
reasonable basis for our opinion.

The accompanying statement of revenues and direct operating expenses was
prepared for the purpose of complying with the rules and regulations of the
Securities and Exchange Commission (for inclusion in the registration statement
on Form S-2 of Callon Petroleum Company) as described in Note 1 and is not
intended to be a complete presentation of the Property's revenues and expenses.

In our opinion, the statement of revenues and direct operating expenses
referred to above presents fairly, in all material respects, the revenues and
direct operating expenses of the Property described in Note 1 for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.

PRICE WATERHOUSE LLP
San Francisco, California
November 21, 1997

F-30
<PAGE>
STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY
(IN THOUSANDS)
<TABLE>
<CAPTION>
FOR THE
NINE MONTHS
ENDED DECEMBER 31,
SEPTEMBER 30, -------------------------------
1997 1996 1995 1994
------------- --------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C> <C>
Oil and gas revenues.................... $ 4,667 $ 8,735 $ 6,612 $ 11,596
Direct operating expenses............... 53 295 334 209
------------- --------- --------- ---------
Revenues in excess of direct operating
expenses.............................. $ 4,614 $ 8,440 $ 6,278 $ 11,387
============= ========= ========= =========
</TABLE>
See accompanying notes.

F-31
<PAGE>
NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE PROPERTY

1. BASIS OF PRESENTATION

Callon Petroleum Operating Company (the "Company"), a wholly owned
subsidiary of Callon Petroleum Company, agreed in October 1997 to acquire 61% of
Chevron U.S.A. Inc.'s working interest in Mobile 864 Unit Outer Continental
Shelf which includes the twelve-inch Mobile 908 Area Gathering Pipeline (the
"Property") for $21 million, effective July 1, 1997. The acquisition closed on
November 7, 1997 for a net acquisition cost of $18.8 million.

The accompanying statement of revenues and direct operating expenses
relates only to the working interest in the producing oil and gas property
acquired and may not be representative of future operations. The statement
includes revenues from natural gas sales and direct operating expenses for each
of the periods presented. The statement does not include federal and state
income taxes, interest, depletion, depreciation and amortization or general and
administrative expenses because such amounts would not be indicative of those
expenses which would be incurred by the Company. Presentation of complete
historical financial statements for each of the three years ended December 31,
1996 and the nine months ended September 30, 1997 is not practicable because the
Property was not accounted for as a separate entity; therefore, such statements
are not available.

Revenues in the accompanying statement of revenues and direct operating
expenses are recognized on the entitlement method.

The accompanying statement has been prepared on the accrual basis in
accordance with generally accepted accounting principles. Preparation of the
statement in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts reported in
the statement and accompanying notes. Actual results could differ from those
estimates.

The interim revenues and direct operating expenses for the nine months
ended September 30, 1997 are unaudited; however, in the opinion of the Company,
the interim revenues and direct operating expenses include all adjustments,
consisting only of normal recurring adjustments, necessary for a fair statement
of the results for the interim period.

2. COMMITMENTS AND CONTINGENCIES

In the normal course of business the Company is subject to possible loss
contingencies arising from federal, state and local environmental, health and
safety laws and regulations, joint venture audit claims and third party
litigation. There are no matters which, in the opinion of management, will have
a material adverse effect on the revenues and direct operating expenses of the
Property.

3. RELATED PARTY TRANSACTIONS

The Property was not operated as a separate entity for the periods
presented in the accompanying statement, but was included in the operations of
Chevron U.S.A. Inc. Effective September 1, 1996, all revenues from production
were transferred to an equity affiliate of Chevron Corporation, the parent of
Chevron U.S.A. Inc., at approximate market prices.

4. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)

The Property's proved oil and gas reserves at December 31, 1996, 1995 and
1994 have been estimated by the Company's independent petroleum consultants in
accordance with guidelines established by the Securities and Exchange Commission
("SEC").

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 Property or the cost that would be
incurred to obtain equivalent reserves.

F-32
<PAGE>
NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE
PROPERTY -- (CONTINUED)

ESTIMATED RESERVES

Changes in the estimated net quantities of natural gas reserves are as
follows:

GAS
NET PROVED RESERVES OF NATURAL GAS (MMCF)
- ------------------------------------- -------
PROVED DEVELOPED AND UNDEVELOPED
RESRVES AT:
December 31, 1993.................... 34,396
Production........................... (6,237)
-------
December 31, 1994.................... 28,159
Production........................... (3,964)
-------
December 31, 1995.................... 24,195
Production........................... (3,394)
-------
December 31, 1996.................... 20,801
=======

PROVED DEVELOPED RESERVES AT:
December 31, 1994.................... 28,159
December 31, 1995.................... 24,195
December 31, 1996.................... 20,801

STANDARDIZED MEASURE

The following tables present the Property's standardized measure of
discounted future net cash flows and changes therein relating to proved reserves
and were computed using reserve valuations based on regulations prescribed by
the SEC. These regulations provide that the gas price structure utilized to
project future net cash flows reflects current prices at each date presented.
Future production, development and net abandonment costs are based on current
costs without escalation. Estimated future income taxes are calculated by
applying appropriate year-end statutory tax rates. These rates reflect allowable
deductions and tax credits and are applied to estimated future pre-tax net cash
flows, less the tax basis of related assets. The resulting net future cash flows
have been discounted to their present values based on a 10% annual discount
factor (in thousands).

STANDARDIZED MEASURE

DECEMBER 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
Future cash inflows.................. $ 81,746 $ 55,406 $ 49,280
Future production and development
costs.............................. (3,902) (4,344) (4,607)
Future income taxes.................. (18,739) (6,412) (1,978)
---------- ---------- ----------
Future net cash flows undiscounted... 59,105 44,650 42,695
10% annual discount for estimated
timing of cash flows............... (20,286) (15,496) (14,953)
---------- ---------- ----------
Standardized measure of discounted
future net cash flows.............. $ 38,819 $ 29,154 $ 27,742
========== ========== ==========

F-33
<PAGE>
NOTES TO STATEMENT OF REVENUES AND DIRECT OPERATING EXPENSES OF THE
PROPERTY -- (CONTINUED)

CHANGES IN STANDARDIZED MEASURE

DECEMBER 31,
--------------------------------
1996 1995 1994
--------- --------- ----------
Standardized measure of discounted
future net cash flows at beginning
of period.......................... $ 29,154 $ 27,742 $ 40,759
Changes resulting from:
Sales of natural gas produced,
net of production costs....... (8,440) (6,278) (11,387)
Net changes in sales prices, net
of production costs........... 22,892 7,689 (9,038)
Accretion of discount........... 3,334 2,902 4,498
Net changes in income taxes..... (8,121) (2,901) 2,910
--------- --------- ----------
Standardized measure of discounted
future net cash flows at end of
period............................. $ 38,819 $ 29,154 $ 27,742
========= ========= ==========

F-34

<PAGE>
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS IN CONNECTION WITH THIS OFFERING
OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS. ANY INFORMATION OR REPRESENTATION
NOT HEREIN CONTAINED IF GIVEN OR MADE, MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL,
OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES
OFFERED BY THIS PROSPECTUS, NOR DOES IT CONSTITUTE AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY THE SECURITIES BY ANY PERSON IN ANY JURISDICTION
WHERE SUCH OFFER OR SOLICITIATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON
MAKING SUCH OFFER IS NOT QUALIFIED TO DO SO, OR TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. THE DELIVERY OF THIS PROSPECTUS
SHALL NOT, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN
NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE
HEREOF.

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

TABLE OF CONTENTS

PAGE
-----
Prospectus Summary................... 3
Risk Factors......................... 10
The Company.......................... 15
Use of Proceeds...................... 15
Price Range of Common Stock and
Dividend Policy.................... 16
Capitalization....................... 17
Selected Financial Data.............. 18
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 20
Business and Properties.............. 26
Management........................... 40
Principal Stockholders............... 43
Description of Outstanding Securities
and Debt Instruments............... 46
Underwriting......................... 50
Legal Matters........................ 51
Experts.............................. 51
Available Information................ 52
Incorporation of Certain Documents by
Reference.......................... 52
Glossary............................. 54
Index to Financial Statements........ F-1

1,600,000 SHARES
CALLON PETROLEUM
COMPANY
COMMON STOCK

-------------------
PROSPECTUS
-------------------

MORGAN KEEGAN & COMPANY, INC.
A.G. EDWARDS & SONS, INC.
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
JEFFERIES & COMPANY, INC.

November 25, 1997