<PAGE> 1
Filed Pursuant to Rule 424b(5)
Registration No. 333-87945
The information in this prospectus supplement is not complete and may be
changed. This prospectus supplement is not an offer to sell these securities,
and we are not soliciting an offer to buy these securities, in any state where
the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED OCTOBER 12, 1999
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED OCTOBER 6, 1999)
3,200,000 SHARES
CALLON PETROLEUM COMPANY
[LOGO]
COMMON STOCK
---------------------------
Callon Petroleum Company is offering 3,200,000 shares of common stock. Our
common stock is listed on the New York Stock Exchange under the symbol "CPE." On
October 12, 1999, the last reported sales price of our common stock on the NYSE
was $14.1875 per share.
---------------------------
INVESTING IN OUR COMMON STOCK INVOLVES RISKS.
SEE "RISK FACTORS" BEGINNING ON PAGE S-9.
---------------------------
PRICE $ A SHARE
---------------------------
<TABLE>
<CAPTION>
PER SHARE TOTAL
--------------- ---------------
<S> <C> <C>
Public offering price....................................... $ $
Underwriting discount....................................... $ $
Proceeds, before expenses, to Callon Petroleum Company...... $ $
</TABLE>
Callon Petroleum Company has granted the underwriters the right to purchase
up to an additional 480,000 shares of common stock to cover over-allotments. The
underwriters expect to deliver the shares to purchasers on ,
1999.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus supplement or the accompanying prospectus is truthful or complete.
Any representation to the contrary is a criminal offense.
---------------------------
A.G. EDWARDS & SONS, INC.
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
JOHNSON RICE & COMPANY L.L.C.
MORGAN KEEGAN & COMPANY, INC.
Prospectus supplement dated , 1999
<PAGE> 2
[MAP SHOWING PRINCIPLE AREAS OF OPERATIONS IN THE GULF OF MEXICO]
CORPORATE PROFILE
- Geographic concentration in the Gulf of Mexico.
- Estimated net proved reserves of 181.8 Bcfe with a discounted present
value of $184.4 million as of July 1, 1999.
- Average daily net production of 43.6 MMcfe during the first half of 1999,
86.7% of which was natural gas.
- Reserve life of 12.2 years.
212% RESERVE GROWTH
- Between January 1, 1996 and July 1, 1999, estimated net proved reserves
increased 212% from 58.3 Bcfe to 181.8 Bcfe.
SIGNIFICANT DEEP WATER SUCCESS (See inside back cover for maps)
- In September 1998, we announced a discovery on our Boomslang prospect,
and in February 1999, we announced a discovery on our Habanero prospect.
These two discoveries represent the largest discoveries in our history
and have added estimated net proved reserves of 86.8 Bcfe at a cost to us
of $10.2 million to drill.
- In addition, in September 1999, we announced a discovery on our Medusa
prospect, our third consecutive deep water discovery.
SUBSTANTIAL INVENTORY OF PROSPECTS
- We currently have an inventory of 41 exploratory prospects, all of which
have been defined by seismic data and interpretation.
S-2
<PAGE> 3
PROSPECTUS SUPPLEMENT SUMMARY
This summary highlights selected information from this document but does
not contain all of the information you need to consider in making your
investment decision. To understand all of the terms of this offering and for a
more complete understanding of our business, you should carefully read this
entire prospectus supplement, the accompanying prospectus and the documents
incorporated by reference, particularly the section entitled "Risk Factors."
When we use the terms "Callon," "we," "us" or "our," we are referring to Callon
Petroleum Company together with its consolidated subsidiaries and predecessors,
unless the context otherwise requires. If you are not familiar with the
ownership of oil and gas properties or the way in which quantities and values of
oil and gas reserves are described, please read "Glossary of Oil and Gas Terms"
included in this document.
ABOUT CALLON
Callon has been engaged in the exploration, development, acquisition and
production of oil and gas properties in the Gulf Coast region since 1950. Our
properties and operations are geographically concentrated in the offshore waters
of the Gulf of Mexico where we have substantial experience. We have historically
grown our reserves and production by focusing primarily on low to moderate risk
exploration and acquisition opportunities in the shallow Miocene and outer
continental shelf ("OCS") areas of the Gulf of Mexico. Over the last several
years, we have expanded our areas of exploration to include the deep water area
(900 to 5,500 feet of water) of the Gulf of Mexico. In September 1998, we
announced our first deep water discovery on our Boomslang prospect. Since the
Boomslang discovery, we have drilled two additional deep water discoveries on
our Habanero and Medusa prospects. Our production and current inventory of
exploration prospects is described below:
<TABLE>
<CAPTION>
FOR THE PERIOD
OCTOBER 1, 1999 TO
DECEMBER 31, 2000
------------------------
PERCENT OF BUDGETED
CURRENT IDENTIFIED BUDGETED CAPITAL
PRINCIPAL AREAS PRODUCTION(1) PROSPECTS WELLS EXPENDITURES
--------------- ------------- ---------- -------- -------------
(IN MILLIONS)
<S> <C> <C> <C> <C>
Shallow Miocene Area............................. 55.5% 3 -- $ --
Outer Continental Shelf Area..................... 32.6% 22 14 42.6
Deep Water Area.................................. -- 16 5 37.0
---- -- -- -----
Total.................................. 88.1% 41 19 $79.6
==== == == =====
</TABLE>
- ---------------
(1) Represents percentage of average daily net production on an Mcfe basis for
the first half of 1999.
Our reserves and production have grown rapidly since 1996 as a result of
exploration and development drilling, as well as property acquisitions. The
following is a profile of our reserves and production and summarizes our recent
growth:
- Between January 1, 1996 and July 1, 1999, estimated net proved reserves
increased 212%.
- As of July 1, 1999, we had estimated net proved reserves of 181.8 Bcfe
which had a discounted present value of $184.4 million. Reserves
comprising 64.1% of this discounted present value were classified as
proved developed.
- Net proved reserves as of July 1, 1999 divided by our production from the
four quarters ended June 30, 1999, which we refer to as our "reserve
life," was 12.2 years.
- Average daily net production increased 71.6% from the first quarter of
1996 to the second quarter of 1999.
- Average daily net production during the first half of 1999 was 43.6
MMcfe, of which 86.7% was natural gas. We operate wells representing
approximately 80% of this production.
- Our reserve replacement costs for the period January 1, 1996 to June 30,
1999 were $1.04 per Mcfe.
S-3
<PAGE> 4
BUSINESS STRATEGY
Our goals are to increase reserves, production, cash flow and earnings at
low reserve replacement costs. We seek to achieve these goals through the
following strategies:
- Assemble and explore a balanced portfolio of projects in the Gulf of
Mexico composed of:
-- Controlling working interests in projects with low exploration risk
and low drilling and completion costs targeting reserve deposits of
between 3 and 10 Bcf in the shallow Miocene area at well depths of
less than 4,000 feet;
-- Significant working interests in projects with moderate exploration
risk and higher drilling and completion costs targeting reserve
deposits of between 10 and 100 Bcfe in the OCS area at well depths
of between 7,000 and 17,000 feet; and
-- Smaller working interests in projects with high exploration risk
and high drilling and completion costs targeting large reserve
deposits in the deep water area of the Gulf of Mexico.
- Acquire at low costs, additional working interests, gathering systems,
pipelines, production facilities and other infrastructure in areas in
which we operate. Ownership of these facilities enables us to reduce the
costs of completing wells and to control the timing of the development of
our properties.
- Utilize the latest available technology. Our geoscientists and petroleum
engineers have developed an expertise with advanced technologies,
including 3-D seismic interpretation and computer-aided exploration. In
addition, we have developed a proprietary, inexpensive, high-resolution
2-D seismic data processing and interpretation technique to target
shallow Miocene formations.
- Maintain financial flexibility. We seek to maintain a substantial unused
borrowing capacity under our bank credit facility by periodically
refinancing our bank debt in the capital markets by issuing both debt and
equity securities.
EXPLORATION OPERATIONS
We explore for oil and gas in the state and federal waters of the Gulf of
Mexico. Since 1996, we have drilled 11 gross (6.0 net) productive exploration
wells and ten gross (4.4 net) dry holes in the Gulf of Mexico for a gross
success rate of 52.4% (57.7% net). We have also drilled five gross (2.9 net)
development wells in the Gulf of Mexico, all of which were successful. We
currently have one gross (0.8 net) exploration well in the OCS area in progress.
Our principal areas of exploration are summarized below. See "Business and
Properties."
Shallow Miocene Area. In the shallow Miocene area, we explore for gas
deposits using 3-D and conventional 2-D seismic technology, as well as a
proprietary high-resolution 2-D seismic data processing and interpretation
technique which better defines reservoir thickness and continuity. We have an
average working interest in productive wells in the shallow Miocene area of
83.3%, all of which we operate. Since 1996, we have drilled four gross (3.7 net)
exploration wells, of which two gross (2.0 net) were productive, and two gross
(1.5 net) development wells, both of which were productive. We have acquired an
extensive infrastructure of production platforms, gathering systems and
pipelines located in our shallow Miocene area. These facilities reduce the
development costs of our successful wells and reduce the time necessary to begin
production from successful wells. In 1997, we also acquired 52.5 Bcf of
estimated net proved reserves in the Mobile Block 864 area for a total
acquisition cost of $48.7 million. We currently have an inventory of three
exploration prospects in the shallow Miocene area.
S-4
<PAGE> 5
Outer Continental Shelf Area. We explore for oil and gas deposits in the
OCS area of the Gulf of Mexico using the latest in 3-D seismic technology. The
wells drilled in this area are more expensive than the shallow Miocene wells and
target larger oil and gas deposits. Our weighted average working interest in
productive wells in the OCS area is 65.4%. Since 1996, we have drilled 14 gross
(6.0 net) exploration wells in this area, of which six gross (3.3 net) were
productive, and we currently have one gross (0.8 net) exploration well in
progress. We also drilled three gross (1.4 net) development wells, all of which
were successful. We currently have an inventory of 22 exploration prospects in
this area, 14 of which we expect to drill before year-end 2000.
Deep Water Area. We allocate a portion of our capital expenditure budget to
the exploration of deep water regions in the Gulf of Mexico. These wells are
expensive to drill and complete and target large reserve deposits. These wells
are usually located far from production facilities and may require long lead
times to construct pipelines and other facilities necessary to begin production.
To reduce the risks associated with the high cost of these wells, we explore
these prospects with experienced joint venture partners, including Shell
Deepwater Development, Inc., Vastar Resources, Inc. and Murphy Exploration and
Production, Inc., as operators. We have drilled three gross (0.6 net)
exploration wells in our deep water area, all of which were successful. In
September 1998, we announced our first deep water discovery on our Boomslang
prospect which was followed in February 1999 with a discovery on our Habanero
prospect. These discoveries represent the largest discoveries in our history and
have added estimated net proved reserves of 86.8 Bcfe at July 1, 1999. In
September 1999, we announced a discovery on our Medusa prospect. We currently
have an inventory of 16 deep water exploration prospects, five of which we
expect to drill before year-end 2000.
RECENT DEVELOPMENTS
In September 1999, we announced a discovery on our Medusa prospect in the
deep water area. This well was drilled in 2,100 feet of water to a measured
depth of 16,241 feet. We have a 15.0% working interest in this well, which
encountered over 120 feet of productive sands in two intervals.
In June 1999, we acquired Murphy's working interests in nine blocks in the
shallow Miocene area in which we already owned an interest. Included in the
acquisition is a 13.1% working interest in four producing wells in the Mobile
Block 864 unit and a 38.6% average working interest in three additional
producing wells. Murphy will receive a production payment entitling it to 7.6
Bcf of gas from production attributable to the wells over three and a quarter
years. Through this acquisition, we also gained operating control of 58,000
gross acres. After giving effect to the acquisition as if it had occurred on
January 1, 1999, our average daily net production would have increased by 5.0
MMcf, or 11.5%, during the first half of 1999.
In February 1999, we announced a discovery on our Habanero prospect in the
deep water area. This well was drilled in 2,000 feet of water to a total
measured depth of 21,158 feet. We have an 11.3% working interest in this well,
which had estimated net proved reserves as of July 1, 1999 of 50.9 Bcfe.
In January 1999, we announced a discovery on our Snapper prospect in the
OCS area. This well was drilled in 210 feet of water to a total measured depth
of 8,800 feet. We have a 50.0% working interest in this well, which had
estimated net proved reserves as of July 1, 1999 of 4.9 Bcfe.
In September 1998, we announced a discovery on our Boomslang prospect in
the deep water area. This well was drilled in 900 feet of water to a total
measured depth of 13,200 feet. We have a 35.0% working interest in this well,
which had estimated net proved reserves as of July 1, 1999 of 35.9 Bcfe.
S-5
<PAGE> 6
SIGNIFICANT PROPERTIES
The following table provides information about estimated net proved
reserves attributable to our principal operating areas as of July 1, 1999.
Estimated net quantities of proved oil and gas reserves and the discounted
present value of the reserves were estimated by our independent reserve
engineers.
<TABLE>
<CAPTION>
ESTIMATED NET PROVED RESERVES PERCENT
------------------------------ DISCOUNTED TOTAL
GAS OIL TOTAL PRESENT VALUE DISCOUNTED
(MMCF) (MBBLS) (MMCFE) ($000) PRESENT VALUE
-------- -------- -------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Shallow Miocene area................... 57,072 -- 57,072 $ 66,804 36.2%
OCS area............................... 20,446 940 26,086 35,748 19.4%
Deep water area(1)..................... 20,829 10,994 86,793 66,274 36.0%
Other areas............................ 5,302 1,093 11,860 15,534 8.4%
------- ------ ------- -------- ------
Total........................ 103,649 13,027 181,811 $184,360 100.0%
======= ====== ======= ======== ======
</TABLE>
- ---------------
(1) Does not include reserves attributable to our discovery on the Medusa
prospect, which was announced in September 1999.
PRINCIPAL OFFICE
Our principal executive offices are located at 200 North Canal Street,
Natchez, Mississippi 39120 and our telephone number is (601) 442-1601.
THE OFFERING
Common stock offered....... 3,200,000 shares(1)
Common stock outstanding
after the offering......... 11,757,906 shares(1)(2)
Use of proceeds............ The net proceeds we receive from this offering,
together with our cash flows and borrowings under
our bank credit facility, will be used to fund our
remaining 1999 capital expenditure budget and a
portion of our 2000 capital expenditure budget.
Pending the use of funds to pay capital
expenditures, we will use a portion of the net
proceeds from the sale of the common stock to repay
borrowings under our bank credit facility and the
remainder will be invested in short-term money
market instruments. See "Use of Proceeds."
NYSE symbol................ "CPE"
- ---------------
(1) Does not include up to 480,000 shares of common stock that the underwriters
may purchase if they exercise their over-allotment option.
(2) Does not include 1,529,000 shares of common stock issuable pursuant to
options granted under our employee stock incentive plans or 2,376,333 shares
of common stock issuable upon the conversion of our Series A Preferred Stock
into common stock.
S-6
<PAGE> 7
SUMMARY FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
The following is our summary financial data. For further information that
will help you better understand the summary data, see "Selected Financial Data"
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
1999 1998 1998 1997 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales......................... $ 16,537 $ 20,322 $ 35,624 $ 42,130 $ 25,764
Interest and other........................ 868 903 2,094 1,508 946
-------- -------- -------- -------- --------
Total revenues.................... 17,405 21,225 37,718 43,638 26,710
-------- -------- -------- -------- --------
Costs and expenses:
Lease operating expenses.................. 3,486 4,089 7,817 8,123 7,562
Depreciation, depletion and
amortization........................... 7,952 10,466 19,284 16,488 9,832
General and administrative................ 2,440 2,732 5,285 4,433 3,495
Interest.................................. 2,471 983 1,925 1,957 313
Accelerated vesting and retirement
benefits............................... -- -- 5,761 -- --
Impairment of oil and gas properties...... -- -- 43,500 -- --
-------- -------- -------- -------- --------
Total costs and expenses.......... 16,349 18,270 83,572 31,001 21,202
-------- -------- -------- -------- --------
Income (loss) from operations............... 1,056 2,955 (45,854) 12,637 5,508
Income tax expense (benefit)................ 359 1,001 (15,100) 4,200 50
-------- -------- -------- -------- --------
Net income (loss)........................... 697 1,954 (30,754) 8,437 5,458
Preferred stock dividends................... 1,386 1,398 2,779 2,795 2,795
-------- -------- -------- -------- --------
Net income (loss) available to common
shares.................................... $ (689) $ 556 $(33,533) $ 5,642 $ 2,663
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic..................................... $ (.08) $ .07 $ (4.17) $ .91 $ .46
Diluted................................... $ (.08) $ .07 $ (4.17) $ .88 $ .45
Shares used in computing net income (loss)
per common share:
Basic..................................... 8,462 8,021 8,034 6,194 5,835
Diluted................................... 8,462 8,233 8,034 6,422 5,952
STATEMENT OF CASH FLOWS DATA:
Cash provided by operating activities....... $ 9,322 $ 16,185 $ 29,721 $ 27,337 $ 14,323
Cash provided by (used in) investing
activities................................ (25,129) 6,435 (54,196) (85,159) (36,063)
Cash provided by (used in) financing
activities................................ 16,841 (1,294) 15,178 65,750 25,144
BALANCE SHEET DATA (END OF PERIOD):
Working capital (deficit)................... $ (2,476) $ 15,270 $ 1,142 $ 12,719 $ 4,878
Oil and gas properties, net................. 173,567 151,074 141,905 150,494 82,489
Total assets................................ 211,826 209,923 181,652 190,421 118,520
Total debt.................................. 101,013 60,250 81,250 60,250 24,250
Stockholders' equity........................ 82,400 115,231 84,484 113,701 77,864
OTHER FINANCIAL DATA:
Capital expenditures, net................... $ 25,129 $ (6,435) $ 54,196 $ 85,159 $ 36,063
EBITDA...................................... 11,902 16,011 27,564 33,209 16,138
</TABLE>
S-7
<PAGE> 8
SUMMARY OPERATING AND RESERVE DATA
The following is our summary operating and reserve data. For further
information that will help you better understand the summary data, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
SIX MONTHS
ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
--------------- --------------------------
1999 1998 1998 1997 1996
------ ------ ------- ------- ------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls)......................................... 176 193 310 462 585
Gas (MMcf).......................................... 6,843 7,676 14,036 13,114 6,269
Total production (MMcfe).................. 7,898 8,835 15,894 15,887 9,781
AVERAGE SALES PRICE(1):
Oil (per Bbl)....................................... $11.96 $13.06 $ 12.41 $ 18.63 $18.27
Gas (per Mcf)....................................... 2.11 2.32 2.26 2.56 2.40
Total production (per Mcfe)............... 2.09 2.30 2.24 2.65 2.63
AVERAGE COSTS (PER MCFE):
Lease operating expenses (excluding severance
taxes)............................................ $ .38 $ .39 $ .44 $ .42 $ .57
Severance taxes..................................... .06 .07 .06 .09 .20
Depreciation, depletion and amortization............ 1.01 1.18 1.19 1.04 1.01
General and administrative (net of management
fees)............................................. .31 .31 .33 .28 .36
</TABLE>
- ---------------
(1) Includes the effects of hedging.
<TABLE>
<CAPTION>
DECEMBER 31,
JULY 1, ------------------------------
1999 1998 1997 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C>
ESTIMATED NET PROVED RESERVES:
Oil (MBbls)....................................... 13,027 6,898 3,402 3,819
Gas (MMcf)........................................ 103,649 88,030 88,738 50,424
Gas equivalent (MMcfe)............................ 181,811 129,418 109,150 73,338
Estimated future net cash flows before income
taxes (000s).................................... $300,042 $152,552 $209,260 $216,154
Discounted present value (000s)................... $184,360 $ 99,751 $136,448 $160,171
OTHER RESERVE DATA:
Reserve replacement costs ($/Mcfe)................ $ .66 $ 1.29 $ 1.45 $ .73
Reserve life (years).............................. 12.2 8.1 6.9 7.5
</TABLE>
S-8
<PAGE> 9
RISK FACTORS
You should carefully consider all of the information we have included in
this document and the documents we have included or incorporated by reference
before purchasing our common stock.
OIL AND GAS PRICES ARE VOLATILE.
Our success is highly dependent on prices for oil and gas, which are
extremely volatile. Beginning in 1997 and continuing through earlier this year,
the prices we received for our production generally declined, especially for
oil. Oil prices have recently recovered, but remain volatile. Any additional
substantial or extended decline in the price of oil or gas would have a material
adverse effect on us. Oil and gas markets are both seasonal and cyclical. The
prices of oil and gas depend on factors we cannot control such as weather,
economic conditions, levels of production, actions by the Organization of
Petroleum Exporting Countries and other countries and government actions. Prices
of oil and gas affect the following aspects of our business:
- our revenues, cash flows and earnings;
- our ability to attract capital to finance our operations and the cost of
the capital;
- the amount we are allowed to borrow under our bank credit facility;
- the value of our oil and gas properties; and
- the profit or loss we incur in exploring for and developing our reserves.
WE MAY BE UNABLE TO REPLACE RESERVES THAT WE HAVE PRODUCED.
Our future success depends upon our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. As is generally the case
in the offshore waters of the Gulf Coast, our producing properties usually have
high initial production rates, followed by a steep decline in production. As a
result, we must locate and develop or acquire new oil and gas reserves to
replace those being depleted by production. We must do this even during periods
of low oil and gas prices when it is difficult to raise the capital necessary to
finance these activities. Without successful exploration or acquisition
activities, our reserves, production and revenues will decline rapidly. We
cannot assure you that we will be able to find and develop or acquire additional
reserves at an acceptable cost.
Also, our return on the investment we make in our oil and gas wells and the
value of our oil and gas wells will depend significantly on prices prevailing
during relatively short production periods.
OUR FOCUS ON EXPLORATORY PROJECTS INCREASES THE RISKS INHERENT IN OUR OIL AND
GAS ACTIVITIES.
Our business strategy focuses on replacing reserves through exploration,
where the risks are greater than in acquisitions and development drilling.
Although we have been successful in exploration in the past, we cannot assure
you that we will continue to increase reserves through exploration.
WE DO NOT CONTROL ALL OF OUR OPERATIONS, ESPECIALLY OUR DEEP WATER OPERATIONS.
We do not operate all of our properties and have limited influence over the
operations of some of these properties, particularly our deep water projects.
Our lack of control could result in the following:
- the operator may initiate exploration or development on a faster or
slower pace than we prefer;
- the operator may propose to drill more wells or build more facilities on
a project than we have funds for or that we deem appropriate, which may
mean that we are unable to participate in the project or share in the
revenues generated by the project even though we paid our share of
exploration costs; and
- if an operator refuses to initiate a project, we may be unable to pursue
the project.
Any of these events could reduce the value of our properties.
S-9
<PAGE> 10
OUR DEEP WATER OPERATIONS HAVE SPECIAL OPERATIONAL RISKS THAT MAY NEGATIVELY
AFFECT THE VALUE OF THOSE ASSETS.
Drilling operations in the deep water area are by their nature more
difficult and costly than drilling operations in shallower water. They require
the application of more advanced drilling technologies, involving a higher risk
of technological failure and usually resulting in significantly higher drilling
costs. Deep water wells are completed using subsea completion techniques that
require substantial time and the use of advanced remote installation equipment.
These operations involve a high risk of mechanical difficulties and equipment
failures that could result in significant cost overruns.
In the deep water area, the time required to commence production following
a discovery is much longer than in shallow waters and on-shore. All of our deep
water discoveries and prospects will require the construction of expensive
production facilities and pipelines prior to the beginning of production. The
costs and timing of the construction of these facilities cannot be estimated
with certainty, and the accuracy of such estimates will be affected by a number
of factors beyond our control, including the following:
- decisions made by the operators of our deep water wells;
- the availability of materials necessary to construct the facilities;
- proximity of our discoveries to pipelines; and
- the price of oil and natural gas.
Delays and cost overruns in the commencement of production will affect the
value of our deep water prospects and the discounted presented value of reserves
attributable to those prospects set forth and incorporated by reference in this
prospectus supplement.
COMPETITIVE INDUSTRY CONDITIONS MAY NEGATIVELY AFFECT OUR ABILITY TO CONDUCT
OPERATIONS.
Exploration in the Gulf of Mexico has recently received renewed interest,
especially among major and large independent oil companies. The acquisition of
exploration prospects, producing properties and production facilities in the
Gulf of Mexico is highly competitive. Factors which affect our ability to
successfully compete are:
- our access to the capital necessary to drill wells and acquire
properties;
- our access to seismic, geological and other information, and our ability
to retain the personnel necessary to properly evaluate such information;
- the location of, and our ability to access, platforms, pipelines and
other facilities used to produce and transport oil and gas production;
and
- the standards we establish for the minimum projected return on an
investment of our capital.
Our competitors include major integrated oil companies and large
independent energy companies, many of which have greater financial and other
resources.
WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
UNABLE TO RAISE CAPITAL.
We will be required to make substantial capital expenditures to develop our
existing reserves, and to discover new oil and gas reserves. Historically, we
have financed these expenditures primarily with cash from operations, proceeds
from bank borrowings and proceeds from the sale of debt and equity securities.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Capital Expenditures" for a
discussion of our capital budget. We cannot assure you that we will be able to
raise capital in the future. We also make offers to acquire oil and gas
properties in the ordinary course of our business. If these offers are accepted,
our capital needs may increase substantially.
S-10
<PAGE> 11
We expect to continue using our bank credit facility to borrow funds to
supplement our available cash. The amount we may borrow under our bank credit
facility may not exceed a borrowing base determined by the lenders based on
their projections of our future production, future production costs and taxes
and commodity prices. We cannot control the assumptions the lenders use to
calculate our borrowing base. The lenders may, without our consent, adjust the
borrowing base semiannually, or if we purchase or sell assets, or issue debt
securities. If our borrowings under the bank credit facility exceed the
borrowing base, the lenders may require that we repay the excess. If this were
to occur, we might have to sell assets or seek financing from other sources. We
cannot assure you that we would be successful in selling assets or arranging
substitute financing. For a description of our bank credit facility and its
principal terms and conditions, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources -- Capital Sources ."
INFORMATION IN THIS PROSPECTUS SUPPLEMENT REGARDING OUR PROSPECTS REFLECTS OUR
CURRENT INTENT AND IS SUBJECT TO CHANGE.
We describe our current prospects and our plans to explore these prospects
in this prospectus supplement, including the materials incorporated by
reference. A prospect is a property on which we have identified what our
geoscientists believe, based on available seismic and geological information, to
be indications of hydrocarbons. Our prospects are in various stages of
evaluation, ranging from a prospect which is ready to drill to a prospect which
will require substantial additional seismic data processing and interpretation.
Whether we ultimately drill a prospect may depend on the following factors:
- receipt of additional seismic data or the reprocessing of existing data;
- material changes in oil or gas prices;
- the costs and availability of drilling rigs;
- success or failure of wells drilled in similar formations or which would
use the same production facilities;
- availability and cost of capital;
- changes in the estimates of the costs to drill or complete wells;
- our ability to attract other industry partners to acquire a portion of
the working interest to reduce exposure to costs and drilling risks; and
- decisions of our joint working interest owners.
We will continue to gather data about our prospects, and it is possible
that additional information may cause us to alter our drilling schedule or
determine that a prospect should not be pursued at all. You should understand
that our plans regarding our prospects are subject to change.
YOU SHOULD NOT PLACE UNDUE RELIANCE ON RESERVE INFORMATION BECAUSE RESERVE
INFORMATION REPRESENTS ESTIMATES.
Estimating quantities of proved reserves is inherently imprecise and
involves uncertainties and factors beyond our control. The reserve data in this
prospectus supplement represent only estimates. Such estimates are based upon
assumptions about future production levels, future oil and gas prices and future
operating costs. As a result, the quantity of proved reserves may be subject to
downward or upward adjustment. In addition, estimates of the economically
recoverable oil and gas reserves, classifications of such reserves, and
estimates of future net cash flows, prepared by different engineers or by the
same engineers at different times, may vary substantially. In particular, the
assumptions regarding the timing and costs to commence production from our deep
water wells used in preparing our reserves are subject to revisions over time as
described under "-- Our deep water operations have special operational risks
that may negatively affect the value of those assets." Information about
reserves constitutes forward-looking information. See "Forward-Looking
Statements" for information regarding forward-looking information.
S-11
<PAGE> 12
On July 1, 1999, approximately 48.1% of our estimated net proved reserves
were proved undeveloped, on an Mcfe basis.
WEATHER, UNEXPECTED SUBSURFACE CONDITIONS, AND OTHER UNFORESEEN OPERATING
HAZARDS MAY ADVERSELY IMPACT OUR ABILITY TO CONDUCT BUSINESS.
There are many operating hazards in exploring for and producing oil and
gas, including:
- our drilling operations may encounter unexpected formations or pressures
which could cause damage to equipment or personal injury;
- we may experience equipment failure which curtails or stops production;
and
- we could experience blowouts or other damages to the productive
formations which may require a well to be re-drilled or other corrective
action to be taken.
In addition, any of the foregoing may result in environmental damages for
which we will be liable. Moreover, a substantial portion of our operations are
offshore and are subject to a variety of risks peculiar to the marine
environment such as hurricanes and other adverse weather conditions. Offshore
operations are also subject to more extensive governmental regulation.
We cannot assure you that we will be able to maintain adequate insurance at
rates we consider reasonable to cover our possible losses from operating
hazards. The occurrence of a significant event not fully insured or indemnified
against could materially and adversely affect our financial condition and
results of operations.
WE MAY NOT BE ABLE TO GENERATE SUFFICIENT CASH FLOW TO SERVICE OUR EXISTING
INDEBTEDNESS OR ENSURE THAT FUTURE CREDIT WILL BE AVAILABLE TO US.
At June 30, 1999, after giving pro forma effect to the offering, we would
have had total indebtedness of approximately $100.3 million, and cash and cash
equivalents of $49.0 million. We intend to incur additional indebtedness after
the offering as we execute our business strategy. Our leverage could have
important consequences, including the following:
- we may be unable to refinance existing debt or obtain additional debt or
equity financing in the future;
- we will be required to use a substantial portion of our cash flow from
operations to pay principal and interest on our indebtedness;
- we may be more leveraged than our competitors, which may place us at a
competitive disadvantage; and
- we may be unable to adjust rapidly to changing market conditions.
These consequences could make us more vulnerable than a less leveraged
competitor in the event of a downturn in general economic conditions or our
business.
Our ability to make scheduled payments or to refinance our indebtedness
depends on our future performance and successful implementation of our strategy,
both of which are subject not only to our actions but also to general economic,
financial, competitive, legislative and regulatory conditions, the prevailing
market prices for oil and gas and other factors beyond our control. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
S-12
<PAGE> 13
RESTRICTIVE DEBT COVENANTS LIMIT OUR OPERATIONAL AND CAPITAL FLEXIBILITY.
Our bank credit facility and the indentures relating to our senior
subordinated notes contain significant covenants that, among other things,
restrict our ability to:
- dispose of assets;
- incur additional indebtedness;
- pay dividends on or repurchase our capital stock;
- merge or consolidate; and
- engage in transactions with affiliates.
These restrictions could adversely affect our ability to finance our future
operations or capital needs or engage in other business activities that may be
in the best interests of our stockholders.
Also, our bank credit facility requires us to maintain compliance with the
financial ratios included in that facility. Our ability to comply with these
ratios may be affected by events beyond our control. A breach of any of these
covenants or our inability to comply with the required financial ratios could
result in a default under our revolving credit facility. If a default were to
occur, the lenders could require us to repay all borrowings outstanding under
our bank credit facility or require us to apply all of our available cash to
repay these borrowings. In addition, the lenders could prevent us from making
debt service payments on our senior subordinated notes, which would be a default
under those notes. We cannot assure you that, if the indebtedness under the bank
credit facility or the senior subordinated notes were accelerated, our assets
would be sufficient to repay this indebtedness in full.
THE RECENT DEPRESSED FINANCIAL CONDITIONS IN THE OIL AND GAS INDUSTRY MAY CHANGE
EXPLORATION AND DEVELOPMENT PLANS OR CAUSE DIFFICULTIES IN FINANCING ACTIVITIES.
The recent low prices for oil and gas have reduced the capital available to
many independent oil and gas companies necessary to finance their activities,
and resulted in reduced capital budgets for 1999. As a result, the decision not
to drill or complete a well may be made based on a lack of available capital
rather than the quality of the project. For projects operated by others, we may
be unable to control decisions regarding drilling and completion operations even
if those decisions are made based on capital constraints.
In addition, some of the other working interest owners of our wells may be
unwilling or unable to pay their share of the costs of projects as they become
due. At worst, a working interest owner may declare bankruptcy and refuse or be
unable to pay its share of the cost of a project. In such cases, we could be
required to pay other working interest owner's share of the costs.
WE MAY NOT HAVE PRODUCTION TO OFFSET HEDGES; BY HEDGING, WE MAY NOT BENEFIT FROM
PRICE INCREASES.
Part of our business strategy is to reduce our exposure to the volatility
of oil and gas prices by hedging a portion of our production. In a typical hedge
transaction, we will have the right to receive from the other parties to the
hedge the excess of the fixed price specified in the hedge over a floating price
based on a market index, multiplied by the quantity hedged. If the floating
price exceeds the fixed price, we are required to pay the other parties this
difference multiplied by the quantity hedged. We are required to pay the
difference between the floating price and the fixed price when the floating
price exceeds the fixed price regardless of whether we have sufficient
production to cover the quantities specified in the hedge. Significant
reductions in production at times when the floating price exceeds the fixed
price could require us to make payments under the hedge agreements even though
such payments are not offset by sales of production. Hedging will also prevent
us from receiving the full advantage of increases in oil or gas prices above the
fixed amount specified in the hedge. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Liquidity and Capital
Resources -- Financial Instruments" for a discussion of our hedging practices.
S-13
<PAGE> 14
COMPLIANCE WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY
AND COULD NEGATIVELY IMPACT PRODUCTION.
Our operations are subject to numerous laws and regulations governing the
discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may:
- require that we acquire permits before commencing drilling;
- restrict the substances that can be released into the environment in
connection with drilling and production activities;
- limit or prohibit drilling activities on protected areas such as wetlands
or wilderness areas; and
- require remedial measures to mitigate pollution from former operations,
such as plugging abandoned wells.
Under these laws and regulations, we could be liable for personal injury
and clean-up costs and other environmental and property damages, as well as
administrative, civil and criminal penalties. We maintain limited insurance
coverage for sudden and accidental environmental damages. We do not believe that
insurance coverage for environmental damages that occur over time is available
at a reasonable cost. Moreover, we do not believe that insurance coverage for
the full potential liability that could be caused by sudden and accidental
environmental damages is available at a reasonable cost. Accordingly, we may be
subject to liability or we may be required to cease production from properties
in the event of environmental damages.
FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION.
The ability to market oil and gas from our wells depends upon numerous
factors beyond our control. These factors include:
- the extent of domestic production and imports of oil and gas;
- the proximity of the gas production to gas pipelines;
- the availability of pipeline capacity;
- the demand for oil and gas by utilities and other end users;
- the availability of alternative fuel sources;
- the effects of inclement weather;
- state and federal regulation of oil and gas marketing; and
- federal regulation of gas sold or transported in interstate commerce.
Because of these factors, we may be unable to market all of the oil or gas
we produce. In addition, we may be unable to obtain favorable prices for the oil
and gas we produce.
OUR DEBT AGREEMENTS RESTRICT OUR ABILITY TO PAY DIVIDENDS, AND WE DO NOT INTEND
TO PAY DIVIDENDS IN THE FORESEEABLE FUTURE.
Our debt agreements restrict us from declaring or paying dividends on our
common stock. We do not intend to pay cash dividends on the common stock in the
foreseeable future. See "Price Range of Common Stock and Dividend Policy."
SHARES ELIGIBLE FOR FUTURE SALE BY OUR CURRENT STOCKHOLDERS COULD ADVERSELY
AFFECT OUR COMMON STOCK PRICE.
Sales of a substantial number of shares of our common stock in the market
could adversely
affect the price of our common stock. After giving effect to the offering, we
will have approximately 11,757,906 shares of common stock outstanding, assuming
no exercise of the underwriters' over-allotment
S-14
<PAGE> 15
option. Of these, 4,028,244 shares are beneficially owned by persons affiliated
with members of our board of directors and executive officers. Additionally, our
outstanding Series A Preferred Stock may be converted into 2,376,333 shares of
our common stock at a conversion price of $11.00 per share. We may redeem our
Series A Preferred Stock at any time. If the price of our common stock is
substantially in excess of the conversion price of our Series A Preferred Stock
we expect to call the preferred stock for redemption. We expect that most
holders of preferred stock would convert their preferred stock into common stock
rather than have their shares redeemed.
ANTI-TAKEOVER PROVISIONS IN OUR GOVERNING DOCUMENTS AND DEBT INSTRUMENTS COULD
PREVENT OR DELAY A CHANGE IN CONTROL.
Our certificate of incorporation and by-laws and the agreements evidencing
our indebtedness contain provisions that may delay, deter or prevent the
acquisition of us or a substantial portion of our common stock. For example, our
certificate of incorporation and by-laws provide for a board of directors
divided into three classes, each of which contains as nearly equal number of
directors as possible. Only one class of directors stands for election at each
annual meeting. As a result, it would take two years to replace a majority of
our directors.
Also, our certificate of incorporation authorizes our board of directors to
issue preferred stock in one or more series and to fix the rights and
preferences of the preferred stock without stockholder approval. Any series of
preferred stock may be senior to the common shares as to dividends, liquidation
rights and, possibly, voting rights of the common shares. The ability to issue
preferred shares could discourage unsolicited acquisition proposals. In
addition, on a change of control, we may be required to repay or repurchase
outstanding debt at a premium to the principal amount of the debt. Furthermore,
Section 203 of the Delaware corporate law prohibits, in some circumstances,
significant transactions without the approval of the board of directors. These
provisions also may discourage attempted acquisitions, unsolicited or otherwise.
By deterring takeover attempts, these provisions could inhibit an increase in
the market price of the common shares that otherwise might result from a
takeover attempt.
Following the offering, approximately 31.4% of our common stock will be
beneficially owned by persons affiliated with members of our board of directors
and executive officers. This level of stock ownership also may discourage an
unsolicited takeover proposal.
WE FACE A THREAT OF BUSINESS DISRUPTION FROM THE YEAR 2000 ISSUE.
The year 2000 issue refers to the inability of computer and other
information technology systems to properly process date and time information,
stemming from the outdated programming practice of using two digits rather than
four to represent the year in a date. The consequence of the year 2000 issue is
that computer and embedded processing systems are at risk of malfunctioning,
particularly during the transition from 1999 to 2000. The effects of the year
2000 issue are exacerbated by the interdependence of computer and
telecommunications systems throughout the world. This interdependence also
exists among Callon and our vendors, customers and business partners, as well as
with regulators in the United States.
Our operations are highly dependent on automation. The risks to us
associated with the year 2000 issue fall into three general areas:
- failure of our financial and administrative systems which could result in
our receiving incorrect information upon which we base decisions;
- failure of the embedded systems which control our highly automated
production facilities; and
- failure of our suppliers and purchasers to correct their year 2000
problems.
For a description of the steps we have taken to address the year 2000 issue
and the risks associated with year 2000 issues, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Year 2000
Compliance."
S-15
<PAGE> 16
FORWARD-LOOKING STATEMENTS
In this prospectus supplement, we have made many forward-looking
statements. We cannot assure you that the plans, intentions or expectations upon
which our forward-looking statements are based will occur. Our forward-looking
statements are subject to risks, uncertainties and assumptions, including those
discussed elsewhere in this prospectus supplement and the documents that are
incorporated by reference into this prospectus supplement. Forward-looking
statements include statements regarding:
- our oil and gas reserve quantities, and the discounted present value of
such reserves;
- the amount and nature of our capital expenditures;
- drilling of wells;
- timing and amount of future production and operating costs;
- business strategies and plans of management;
- prospect development and property acquisitions; and
- ability to deal with the year 2000 problems.
Some of the risks which could affect our future results and could cause
results to differ materially from those expressed in our forward-looking
statements include:
- general economic conditions;
- the volatility of oil and gas prices;
- the uncertainty of estimates of oil and gas reserves and future
production rates;
- the impact of competition;
- availability and cost of seismic, drilling and other equipment;
- operating hazards inherent in the exploration for and production of oil
and gas;
- the difficulties encountered in delivering oil and natural gas to
commercial markets;
- changes in customer demand;
- the uncertainty of our ability to attract capital;
- compliance with, or the effect of changes in, the extensive government
regulations regarding the oil and natural gas business;
- actions of operators of our properties; and
- climactic conditions.
The information contained in this prospectus supplement, including the
information set forth under the heading "Risk Factors," identifies additional
factors that could affect our operating results and performance. We urge you to
carefully consider those factors.
When you consider our forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this prospectus
supplement. Our forward-looking statements speak only as of the date made, and
we have no obligation to update these forward-looking statements.
S-16
<PAGE> 17
USE OF PROCEEDS
Assuming a public offering price of $14.1875, which was the closing price
per share of our common stock on October 12, 1999, we expect to receive
approximately $42.3 million of net proceeds from this offering ($48.7 if the
underwriters' over-allotment option is exercised in full) after deducting the
underwriting discount and estimated offering expenses. We intend to use all of
the net proceeds, together with our cash flows and borrowings under our bank
credit facility, to fund our remaining 1999 and a portion of our 2000 capital
expenditure budget. Our estimated fourth quarter 1999 and 2000 capital budget is
$90.2 million. For a more detailed description of our capital expenditure
budget, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources -- Capital
Expenditures." Pending the use of funds to pay capital expenditures, we will use
a portion of the net proceeds from the sale of our common stock to repay
borrowings under our bank credit facility and the remainder will be invested in
short term money market instruments. Our bank credit facility must be repaid in
full on October 31, 2000. On September 30, 1999, we had $7.1 million outstanding
under our bank credit facility. As of June 30, 1999, borrowings under our bank
credit facility had a weighted average interest rate of 6.53%.
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock has been listed on the New York Stock Exchange under the
symbol "CPE" since April 22, 1998. Before that, it was traded in the Nasdaq
National Market. The following table shows the high and low prices per share of
our common stock as reported by the NYSE and the Nasdaq.
<TABLE>
<CAPTION>
HIGH LOW
------- -------
<S> <C> <C>
1997
First quarter............................................. $19.500 $12.500
Second quarter............................................ 16.375 13.250
Third quarter............................................. 19.375 15.000
Fourth quarter............................................ 22.000 15.000
1998
First quarter............................................. $17.125 $15.000
Second quarter............................................ 18.375 14.000
Third quarter............................................. 14.875 7.875
Fourth quarter............................................ 14.000 10.875
1999
First quarter............................................. $11.875 $ 8.875
Second quarter............................................ 11.250 9.875
Third quarter............................................. 15.375 10.000
Fourth quarter (through October 12], 1999)................ 15.375 14.125
</TABLE>
On October 12, 1999, the last reported sale price of our common stock on
the NYSE was $14.1875. As of June 30, 1999, there were 7,263 record holders of
our common stock.
We have not paid dividends on our common stock in the past, and we do not
intend to do so in the future. We currently intend to reinvest our future cash
flow in the acquisition, exploration and development of properties. Our bank
credit facility and our senior subordinated notes contain provisions limiting
our ability to pay dividends.
S-17
<PAGE> 18
CAPITALIZATION
The following table sets forth our capitalization, as of June 30, 1999, our
pro forma capitalization giving effect to the sale of $40 million in senior
subordinated notes in July 1999, and our pro forma capitalization as adjusted to
give effect to the sale of the common stock in this offering and the application
of the estimated net proceeds.
For a description of the application of the net proceeds, see "Use of
Proceeds." You should read this information in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the consolidated financial statements and notes thereto included and
incorporated by reference in this document.
<TABLE>
<CAPTION>
JUNE 30, 1999
-----------------------------------------
PRO FORMA
AS
HISTORICAL PRO FORMA(1) ADJUSTED(2)
---------- ------------ -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash and cash equivalents............................... 7$,334.... $ 7,334 $ 48,987
======== ======== ========
Long-term debt:
Credit facility....................................... $ 39,100 $ 700 $ 100
10% senior subordinated notes......................... 24,150 24,150 24,150
10.125% senior subordinated notes..................... 36,000 36,000 36,000
10.25% senior subordinated notes...................... -- 40,000 40,000
Stockholders' equity:
Preferred stock, $0.01 par value, 2,500,000 shares
authorized; 1,045,461 shares of Convertible
Exchangeable Preferred Stock, Series A issued and
outstanding with a liquidation preference of
$26,136,525........................................ 10 10 10
Common stock, $0.01 par value, 20,000,000 shares
authorized; 8,545,517 shares outstanding and
11,745,517 shares as adjusted(3)................... 86 86 118
Treasury stock (98,578 shares at cost).................. (1,177) (1,177) (1,177)
Capital in excess of par value.......................... 108,296 108,296 150,517
Retained earnings (deficit)............................. (24,815) (24,815) (24,815)
-------- -------- --------
Total stockholders' equity.................... 82,400 82,400 124,653
-------- -------- --------
Total capitalization.......................... $181,650 $183,250 $224,903
======== ======== ========
</TABLE>
- ---------------
(1) Gives effect to the sale of the 10.25% Senior Subordinated Notes as if it
had occurred on June 30, 1999 and the use of the net proceeds of $38.4
million to repay amounts outstanding under our bank credit facility.
(2) As adjusted to reflect the sale of common stock in this offering as if it
had occurred on June 30, 1999 and application of the net proceeds as
described under "Use of Proceeds."
(3) Does not include 1,529,000 shares of common stock issuable pursuant to
options granted under our employee stock incentive plans or 2,376,333 shares
of common stock issuable upon the conversion of our Series A Preferred Stock
into common stock. Also does not include up to 480,000 shares of common
stock that the underwriters may purchase if they exercise their
over-allotment option. See "Underwriting."
S-18
<PAGE> 19
SELECTED FINANCIAL DATA
The following table shows selected financial data for the five years ended
December 31, 1998 and for the six months ended June 30, 1999 and 1998. The
financial data for each of the three years in the period ended December 31, 1998
has been derived from our audited consolidated financial statements for these
periods which are included and incorporated by reference in this prospectus
supplement. The financial data for the years ended December 31, 1995 and 1994
has been derived from our audited financial statements. The financial data for
each of the six-month periods ended June 30, 1999 and 1998 has been derived from
our unaudited consolidated financial statements for these periods which are also
included in this prospectus supplement. You should read this data in conjunction
with "Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the consolidated financial statements and notes thereto included
and incorporated by reference in this document. The selected financial data is
not necessarily indicative of our future results.
The following information will help you to better understand the selected
and summary financial data.
- Callon was formed on September 16, 1994. Historical information prior to
September 16, 1994 includes financial and operating information of our
predecessors.
- EBITDA is net income before interest expense, income tax expense,
depreciation, depletion and amortization and other non-cash charges.
EBITDA is presented because it is a widely accepted financial indication
of a company's ability to service and incur debt. EBITDA should not be
considered as an alternative to earnings (loss) as an indicator of our
operating performance or to cash flow as a measure of liquidity.
- We use the full-cost method of accounting. Under this method of
accounting, our net capitalized costs to acquire, explore and develop oil
and gas properties may not exceed the standardized measure of our proved
reserves. If these capitalized costs exceed the standardized measure, the
excess is charged to expense. As a result of the significant decline in
oil and gas prices, we recorded a non-cash impairment expense related to
our oil and gas properties in the amount of $43.5 million ($28.7 million
after-tax) during the fourth quarter of 1998. The process used to
calculate the standardized measure is described under "Glossary of Oil
and Gas Terms."
S-19
<PAGE> 20
<TABLE>
<CAPTION>
SIX MONTHS
ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ----------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales........... $ 16,537 $ 20,322 $ 35,624 $ 42,130 $ 25,764 $ 23,210 $ 13,948
Interest and other.......... 868 903 2,094 1,508 946 627 171
-------- -------- -------- -------- -------- -------- --------
Total revenues............ 17,405 21,225 37,718 43,638 26,710 23,837 14,119
-------- -------- -------- -------- -------- -------- --------
Costs and expenses:
Lease operating expenses.... 3,486 4,089 7,817 8,123 7,562 6,732 4,042
Depreciation, depletion and
amortization.............. 7,952 10,466 19,284 16,488 9,832 10,376 6,049
General and
administrative............ 2,440 2,732 5,285 4,433 3,495 3,880 3,717
Interest.................... 2,471 983 1,925 1,957 313 1,794 624
Accelerated vesting and
retirement benefits....... -- -- 5,761 -- -- -- --
Impairment of oil and gas
properties................ -- -- 43,500 -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Total costs and
expenses............... 16,349 18,270 83,572 31,001 21,202 22,782 14,432
-------- -------- -------- -------- -------- -------- --------
Income (loss) from
operations.................. 1,056 2,955 (45,854) 12,637 5,508 1,055 (313)
Income tax expense
(benefit)................... 359 1,001 (15,100) 4,200 50 -- (200)
-------- -------- -------- -------- -------- -------- --------
Net income (loss)............. 697 1,954 (30,754) 8,437 5,458 1,055 (113)
Preferred stock dividends..... 1,386 1,398 2,779 2,795 2,795 256 --
-------- -------- -------- -------- -------- -------- --------
Net income (loss) available to
common shares............... $ (689) $ 556 $(33,533) $ 5,642 $ 2,663 $ 799 $ (113)
======== ======== ======== ======== ======== ======== ========
Net income (loss) per common
share:
Basic....................... $ (.08) $ .07 $ (4.17) $ .91 $ .46 $ .14 $ (.03)
Diluted..................... $ (.08) $ .07 $ (4.17) $ .88 $ .45 $ .14 $ (.03)
Shares used in computing net
income (loss) per common
share:
Basic....................... 8,462 8,021 8,034 6,194 5,835 5,755 4,346
Diluted..................... 8,462 8,233 8,034 6,422 5,952 5,755 4,346
STATEMENT OF CASH FLOWS DATA:
Cash provided by operating
activities.................. $ 9,322 $ 16,185 $ 29,721 $ 27,337 $ 14,323 $ 9,452 $ 5,347
Cash provided by (used in)
investing activities........ (25,129) 6,435 (54,196) (85,159) (36,063) (24,237) (6,423)
Cash provided by (used in)
financing activities........ 16,841 (1,294) 15,178 65,750 25,144 11,765 3,916
BALANCE SHEET DATA (END OF
PERIOD):
Working capital (deficit)..... $ (2,476) $ 15,270 $ 1,142 $ 12,719 $ 4,878 $ 4,712 $ 1,896
Oil and gas properties, net... 173,567 151,074 141,905 150,494 82,489 57,765 43,920
Total assets.................. 211,826 209,923 181,652 190,421 118,520 83,867 73,786
Total debt.................... 101,013 60,250 81,250 60,250 24,250 100 15,363
Stockholders' equity.......... 82,400 115,231 84,484 113,701 77,864 75,129 43,431
OTHER FINANCIAL DATA:
Capital expenditures, net..... $ 25,129 $ (6,435) $ 54,196 $ 85,159 $ 36,063 $ 24,237 $ 10,412
EBITDA........................ 11,902 16,011 27,564 33,209 16,138 13,582 6,727
</TABLE>
S-20
<PAGE> 21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Since 1996, we have completed several acquisitions that have significantly
affected our results of operations. Through a series of four transactions, we
acquired 52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area
for a total acquisition cost of $48.7 million. In June 1999, in exchange for a
production payment, we acquired Murphy's interest in several wells and
undeveloped acreage in this area which, prior to exploration and development
activities, has added an additional 15.6 Bcf of estimated net proved reserves.
Our results in 1998 were also affected by the sale of our Black Bay
properties which are located in Louisiana state waters. We sold these properties
in April 1998 for $9.4 million, the proceeds of which were used to repay amounts
outstanding under our bank credit facility.
Inflation has not had a material impact on our results of operations and is
not expected to have a material impact on our results of operations in the
future.
Comparison of Results of Operations for the Six Months Ended June 30, 1999 and
1998
Production and Revenues. For the six months ended June 30, 1999, total oil
and gas revenues decreased by $3.8 million, or 19%, to $16.5 million when
compared to $20.3 million for the same period in 1998. When compared to the same
period last year, both oil and gas production and prices declined.
Gas production and revenue for the six-month period ending June 30, 1999
were 6.8 Bcf and $14.4 million, respectively, decreasing from production of 7.7
Bcf and gas revenues of $17.8 million in the first six months of 1998. The
average sales price for natural gas in the first six months in 1999 was $2.11
per Mcf, a $0.21 per Mcf decrease over the same period in 1998. Reduced
production in 1999 was caused primarily by normal production declines,
particularly in shallow Miocene wells which have steep decline rates. These
declines were partially offset by discoveries at Main Pass 26 and Eugene Island
335. In addition, production increased at Main Pass 31, as a result of a
recompletion.
For the six months ending June 30, 1999, oil production and oil revenues
decreased to 176 MBbls and $2.1 million, respectively. For the comparable period
in 1998, oil production was 193 MBbls while revenues totaled $2.5 million. Oil
prices during the first six months of 1999 averaged $11.96, compared with $13.06
for the same period in 1998. The reduced production was primarily attributable
to the sale of Black Bay, which contributed 57 MBbls during the 1998 period, and
normal declines experienced at our Escambia Mineral property. This decline was
offset by production from discoveries at Main Pass 26 and Eugene Island 335,
which added 49 MBbls in the 1999 period.
Lease Operating Expenses. Lease operating expenses, excluding severance
taxes, for the first half of 1999 decreased 14% to $3.0 million from $3.5
million for the 1998 period. This decrease was primarily the result of the sale
of our Black Bay properties in May 1998. Severance taxes were $0.5 million for
the 1999 period which compared with $0.6 million for the first six months of
1998.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for the first six months of 1999 was $8.0 million, or $1.01 per
Mcfe. For the same period in 1998, depreciation, depletion and amortization was
$10.5 million and $1.18 per Mcfe. This decline was primarily a result of lower
production volumes in the 1999 period and a reduction in the depletion rate as a
result of the ceiling test writedown in 1998.
General and Administrative Expenses. During the first six months of 1999,
general and administrative expenses decreased by 11% to $2.4 million compared
with $2.7 million for the six-month period in 1998. The 1998 period included
expenses related to bonuses under the incentive compensation plan and the
vesting of performance shares granted to officers, which were not incurred in
1999. The 1999 period,
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<PAGE> 22
however, included expenses associated with personnel reductions in 1999, which
are not anticipated to recur in the future.
Interest Expense. Interest expense during the first half of 1999 was $2.5
million compared with $1.0 million for the first half of 1998, resulting from
increase in our long-term debt. We capitalized $1.7 million of our interest
charges in the first six months of 1999 as additional property costs associated
with our drilling and exploration activities.
Income Tax Expense. Income taxes were provided for at the expected
statutory rate of 34% of net income.
Preferred Stock Dividends. Preferred stock dividends were $1.4 million for
the first half of 1999 as compared to $1.4 million for the first half of 1998.
During the first quarter of 1999, several preferred stockholders, through
private transactions, agreed to convert 210,350 shares of Series A Preferred
Stock into 502,632 shares of our common stock. Of these shares of common stock,
24,507 shares were issued in excess of the conversion rate as a result of
private negotiations between us and the holders. These additional shares were
treated as a non-cash dividend on the preferred stock for accounting purposes
and were valued at the market value of the shares on the date of conversion.
Cash dividends on the Series A Preferred Stock will be lower in future quarters
since the number of shares outstanding has been reduced.
Comparison of Results of Operations for the Years Ended December 31, 1998 and
1997
Production and Revenues. Our oil and gas revenues for 1998 were $35.6
million, a 15% reduction from $42.1 million in 1997. On an Mcfe basis, our 1998
production was the same as that reported for 1997. The reduction in our revenues
was attributable to the 15% reduction in average sales price (including the
effects of hedging) per Mcfe.
Our gas revenues for 1998 were $31.8 million, a reduction of 5% from 1997
revenues of $33.5 million. Gas production in 1998 was 14.0 Bcf, an increase of
7% over 1997 production of 13.1 Bcf. The increase in production was attributable
to the beginning of production from exploration successes in 1998. The increases
in production were more than offset by a reduction in average prices (including
the effects of hedging) from $2.56 per Mcf in 1997 to $2.26 in 1998.
Oil revenues declined from $8.6 million to $3.8 million. This decline was
caused in part by reduced oil production, which declined from 462.0 MBbls in
1997 to 310.0 MBbls in 1998 and a decline in average sales prices (including the
effects of hedging) from $18.63 in 1997 to $12.41 in 1998. Approximately 5% of
the reduced production was attributable to the sale of the Black Bay Complex in
1998, and the remainder was attributable to normal production declines.
Lease Operating Expenses. Our lease operating expenses, including severance
taxes, decreased from $8.1 million in 1997 to $7.8 million in 1998. This
decrease was attributable to reduced severance taxes which declined from $1.4
million in 1997 to $0.9 million in 1998 because more of our production was from
federal waters where we do not incur severance taxes. The other components of
operating expenses increased from $6.7 million in 1997 to $6.9 million in 1998
as a result of a full year of costs associated with acquisitions in the fourth
quarter of 1997 that was partially offset by a reduction in costs due to the
sale of the Black Bay properties.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization increased as a higher rate was applied to a relatively constant
production volume. Total charges increased from $16.5 million, or $1.04 per
Mcfe, in 1997 to $19.3 million, or $1.19 per Mcfe in 1998. The increase in the
noncash charge per Mcfe reflects the increase in investment in evaluated oil and
gas properties during 1998.
General and Administrative Expenses. Our general and administrative
expenses for 1998 were $5.3 million, or $0.33 per Mcfe, compared to $4.4
million, or $0.28 per Mcfe, in 1997. This 19% increase was primarily the result
of the loss of Black Bay management fees, which previously reduced general and
administrative expenses, and slightly higher corporate expenses.
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<PAGE> 23
Other. In December 1998, we recorded a charge of $5.8 million attributable
to the accelerated vesting of the remaining unvested performance shares
previously granted under our stock option plans and of retirement benefits.
Interest Expense. Interest expense was $1.9 million for 1998 and $2.0
million for 1997.
Ceiling Test Writedown. Under the full-cost method of accounting, the net
capitalized costs of proved oil and gas properties are subject to a "ceiling
test," which limits such costs to the discounted present value, net of related
tax effects, of proved reserves. If capitalized costs exceed this limit, the
excess is charged to expense. During the fourth quarter of 1998, we recorded a
noncash impairment provision related to oil and gas properties in the amount of
$43.5 million ($28.7 million after-tax) primarily due to the significant decline
in oil and gas prices.
Tax Benefits. Our 1998 results included a deferred income tax benefit of
$15.1 million primarily due to the $14.8 million deferred income tax benefit
related to impairment of oil and gas properties recorded in 1998. We expect to
realize this benefit for tax purposes in future years by utilizing our net
operating loss and statutory depletion carryforwards. We have evaluated the
potential realization of the deferred income tax benefit recorded above in light
of our reserve quantity estimates, our long-term outlook for oil and gas prices
and our expected level of other future expenses. We believe it is more likely
than not, based upon this evaluation, that we will realize the recorded deferred
income tax asset. However, we cannot assure you that such asset will ultimately
be realized.
Comparison of Results of Operations for the Years Ended December 31, 1997 and
1996
Production and Revenues. Our total oil and gas revenues increased $16.4
million, or 63%, during 1997 to $42.1 million compared to $25.8 million in 1996.
This increase in oil and gas revenues was the result of increased gas production
volumes and increased average sales prices (including the effects of hedging)
for both oil and gas.
Our gas revenues for 1997 were $33.5 million from production volumes of
13.1 Bcf of gas sold at an average sales price of $2.56 per Mcf. For 1996, our
revenues were $15.1 million from the production of 6.3 Bcf of gas sold at an
average sales price (including the effects of hedging) of $2.40. The 109%
increase in production volume was largely attributed to our 1996 discoveries in
the OCS and shallow Miocene areas.
Our oil revenues for 1997 were $8.6 million based on production volume of
462.0 MBbls sold at an average sales price of $18.63 per Bbl. For 1996, our
revenues were $10.7 million based on 585.0 MBbls of oil sold at an average sales
price (including the effects of hedging) of $18.27. The $2.1 million decline in
oil revenues was largely attributed to normal production declines from several
of our oil producing properties, as well as the divestiture of certain non-core
properties.
Lease Operating Expenses. Lease operating expenses, including severance
taxes, increased from $7.6 million in 1996 to $8.1 million in 1997. Separately,
severance taxes declined from $1.9 million in 1996 to $1.4 million in 1997 as a
result of lower production on properties subject to severance taxes. Other
operating expenses increased from $5.6 million in 1996 to $6.7 million in 1997
as a result of the new offshore producing properties. On a per Mcfe basis, these
combined expenses decreased from $0.77 in 1996 to $0.51 in 1997.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for 1997 totaled $16.5 million, or $1.04 per Mcfe. For the same
period in 1996, these expenses totaled $9.8 million, or $1.01 per Mcfe.
General and Administrative Expenses. Our general and administrative
expenses for 1997 were $4.4 million, a 27% increase from the $3.5 million in
1996 as a result of expanded levels of operations and production. On a per Mcfe
basis, these expenses decreased from $0.36 in 1996 to $0.28 in 1997.
Interest Expense. Interest expense for 1997 was $2.0 million. The
substantial increase from the $0.3 million in 1996 was reflective of the
issuance of senior subordinated notes in November 1996 and July 1997.
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<PAGE> 24
Income Tax Expense. Income tax expense for 1997 was $4.2 million. This
amount represented the approximate statutory income tax rate, as adjusted for
expected future utilization of our net operating losses and depletion
carryovers. For 1996, the statutory income tax was $1.9 million, which was
primarily offset by a reduction in the deferred tax asset valuation allowance.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources
Our primary sources of capital are our cash flows from operations,
borrowings under our bank credit facility, and sales of debt and equity
securities. Cash flow from operations before working capital changes for the
first half of 1999 and 1998 totaled $9.4 million and $15.0 million,
respectively. During the first six months of 1999, borrowings under our credit
facility increased by $21.0 million. Borrowings under the credit facility did
not increase for the comparable 1998 period. Also during the first half of 1998,
we sold properties in Black Bay for net cash proceeds of $9.4 million, which was
used to reduce the amount outstanding under our credit facility.
Bank credit facility. Borrowings under the bank credit facility are secured
by mortgages covering substantially all of our producing oil and gas properties.
The credit facility provides for a borrowing base which is adjusted periodically
on the basis of the discounted present value attributable to our proved
producing oil and gas reserves, as determined by the bank. The credit facility
currently provides for a $20 million borrowing base although we expect this
borrowing base to increase substantially. We may borrow, pay, reborrow and repay
under the credit facility until October 31, 2000, on which date we must repay in
full all amounts then outstanding. At September 30, 1999, the amount available
to be borrowed under our credit facility was approximately $12.9 million. See
"Description of Bank Credit Facility and Other Indebtedness -- Bank Credit
Facility" for more information about the credit facility.
Material sales of debt and equity securities. In July 1999, we issued $40.0
million of 10.25% senior subordinated notes, in July 1997, we issued $36.0
million of 10.125% senior subordinated notes and in November 1996, we issued
$24.2 million of 10% senior subordinated notes for total net proceeds of $96.2
million. The proceeds of the note offerings were used to repay outstanding
amounts under the bank credit facility and to finance our capital budget. See
"Description of Bank Credit Facility and Other Indebtedness -- Outstanding
Notes" for additional information about our outstanding notes.
On November 25, 1997, we sold 1.8 million shares of our common stock to the
public for total net proceeds of $29.3 million. We used a portion of the
proceeds to repay indebtedness incurred to finance the purchase of properties in
the shallow Miocene area and the balance to fund a portion of our 1998 capital
expenditure budget.
Capital Expenditures
Capital expenditures for the first six months of 1999 and for the year 1998
were $25.1 million and $64.1 million, respectively. The 1999 amounts were used
primarily to drill and complete six wells, and to complete three previously
drilled wells. The 1998 amount included $9.5 million for the acquisition of
producing properties and equipment, $47.0 million for property development and
drilling activities and $7.3 million for the acquisition of oil and gas
properties for exploration.
Our capital expenditure budget for the last half of 1999 is $32.3 million.
Approximately $21.0 million of the capital expenditure budget is anticipated to
be used to drill eight exploration wells. The timing and cost to drill these
wells will depend upon numerous factors, many of which are beyond our control.
In addition, we had a non-cash expenditure during the first half of 1999
related to the acquisition of Murphy's interest in Mobile Block 864. We acquired
Murphy's interest for approximately $15.0 million, financed by a volumetric
production payment.
We make offers for producing properties in the ordinary course of our
business. If we were to purchase a producing property, our capital budget could
change materially.
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<PAGE> 25
Financial Instruments
We periodically use derivative financial instruments to hedge oil and gas
price risks. In a typical hedge transaction, we will have the right to receive
from counterparties to the hedge, the excess of the fixed price specified in the
hedge over a floating price based on a market index, multiplied by the quantity
hedged. If the floating price exceeds the fixed price, we are required to pay
the counterparties the difference multiplied by the quantity hedged. We are
required to pay the difference between the floating price and the fixed price
when the floating price exceeds the fixed price regardless of whether we have
sufficient production to cover the quantities specified in the hedge. If there
are significant reductions in production at times when the floating price
exceeds the fixed price, we could be required to make payments under the hedge
agreements even though such payments are not offset by sales of production.
Hedging will also prevent us from receiving the full advantage of increases in
oil or gas prices above the fixed amount specified in the hedge.
We also enter into price "collars" to reduce the risk of changes in oil and
gas prices. Under a collar, no payments are due by either party so long as the
market price is above a floor set in the collar and below a ceiling. If the
price falls below the floor, the counter-party to the collar pays the difference
to us and if the price is above the ceiling, we pay the counter-party the
difference. We enter into hedge transactions to reduce the effect of volatile
oil and gas prices, and do not enter into hedge transactions for speculative
purposes.
As of June 30, 1999, we had hedged approximately 450 MMcf per month through
November 1999, pursuant to price collars, with an average NYMEX floor price of
$2.02 per MMBtu and an average ceiling price of $2.35 per MMBtu. Also at June
30, 1999, we had open forward natural gas swap contracts of 200 MMcf per month
from July 1999 through September 1999, at a fixed contract average price of
$2.35. In addition, we had oil price collar contracts averaging 25 MBbls per
month from July 1999 through December 1999, at a ceiling price of $16.22 and a
floor of $13.85. We also had open forward crude oil swap contracts of 10 MBbls
per month with a fixed contract price of $14.10 per month from July 1999 through
September 1999. These hedging activities represent approximately 50% of our
estimated production during this period on an Mcfe basis.
Preferred Stock
We currently have outstanding 1,045,461 shares of Series A Preferred Stock,
which is convertible into our common stock at a conversion price of $11.00 per
share. Currently, we may redeem the Series A Preferred Stock for 106% of its
issue price. If the price of our common stock remains substantially in excess of
the Series A Preferred Stock conversion price following this offering, we
currently intend to redeem the Series A Preferred Stock. We expect that holders
of preferred stock will elect to convert their Series A Preferred Stock to
common stock rather than permit the redemption of their Series A Preferred
Stock.
YEAR 2000 COMPLIANCE
Three years ago, we began our efforts to address the threats to our
business posed by the year 2000 issue. For a description of the business
disruption risks we face from the year 2000 issue, see "Risk Factors."
Overseeing the year 2000 project is the Callon Year 2000 Project Committee which
meets on a periodic basis to review project status, provide necessary management
input and resolve project issues on a timely basis. A formal review is presented
to our board of directors periodically.
Our plan is divided into three phases. Phase one involves a physical
inventory of all hardware, software and devices containing date-oriented
firmware. Phase two requires that we prioritize issues, obtain or devise
solutions and make repairs or replace equipment as necessary. The third phase of
the plan calls for the development of contingency plans to address, among other
things, the failure of our business partners to adequately address their year
2000 problems.
We have completed phase one and phase two, and have substantially completed
phase three.
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<PAGE> 26
Accounting systems. Our core financial accounting software is maintained by
one major vendor of oil and gas industry software. The vendor has indicated that
it believes our system is year 2000 compliant.
Embedded chips. A substantial portion of our exploration and production
facilities is automated. These facilities rely on one or more "embedded chips"
to control and measure flow rates, pressures, emissions and other critical
functions. Failure of embedded chips may cause production to stop, spills of
hydrocarbons or other materials and other problems. This problem is complicated
because many of the embedded chips are linked in systems, where the failure of
one part of the system will adversely affect the entire facility.
We believe we have identified all of the embedded systems affecting our
material facilities, tested them for year 2000 compliance and made appropriate
remediation. We therefore do not expect that our embedded systems will suffer
material interruptions caused by year 2000 related failures of our systems. It
must be noted, however, that our facilities have numerous embedded chips many of
which are not easy to locate. In addition, while we believe the testing of chips
will uncover year 2000 failures, until the year 2000 occurs, there is no way to
be sure that the repairs we made will work, or that all of the embedded chips
which must work together in systems will function properly. Because of the
complexity of the year 2000 problem, we cannot assure you that we will not have
a material business interruption caused by the year 2000 problem.
Vendors and customers. We could be adversely affected if our suppliers,
customers or other business partners experience year 2000 failures. For example,
if our electrical supplier fails to deliver electricity to our facilities or if
refineries are unable to receive our oil production, we will suffer losses. We
have requested information from all of our material business partners regarding
their year 2000 readiness. It appears that all of our material business partners
are aware of the year 2000 issues and are attempting to uncover and remedy
potential failures. Where we were not satisfied with the results of our
inquiries, we are attempting to develop contingency plans. However, we do not
believe contingency plans will protect us from loss if there are material year
2000 failures of our business partners. Additionally, we are unable to
independently verify that our business partners are, in fact, taking appropriate
steps to remedy problems. Accordingly, no assurances can be made that year 2000
failures will not adversely affect our business.
Estimated compliance costs. Our total costs incurred to date and estimated
remaining costs for consultants, software and hardware applications for the year
2000 project are less than $200,000. We do not separately account for the
internal costs incurred for our year 2000 compliance efforts, which consist
principally of payroll and related benefits for our informations system
personnel.
Risks of non-compliance. The most reasonably likely "worst case" impact of
the year 2000 issue on our operations could be:
- hydrocarbon spills or other accidents which could result in environmental
pollution, personal injuries or loss of life;
- equipment failures which could curtail, delay or cancel our operations;
- impairment of our ability to deliver our production to, or receive
payment from, third parties gathering and/or purchasing our production
from affected facilities;
- impairment of the ability of third-party suppliers or service companies
to provide needed materials or services to our planned or ongoing
operations, thereby necessitating deferral or shut-in of our operations;
and
- our inability to execute financial transactions with our banks or other
third parties whose systems fail or malfunction.
We have no reason to believe that any of these contingencies will occur or
that our principal vendors, customers and business partners will not be year
2000 compliant.
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<PAGE> 27
DISCLOSURES ABOUT MARKET RISKS
Our revenues are derived from the sale of our oil and natural gas. The
prices of oil and gas are extremely volatile, and experience large fluctuations
as a result of relatively small changes in supplies. For a description of the
effects of the volatility of oil and gas prices on our operations, see "Risk
Factors."
From time to time we enter into arrangements to reduce the effect of
changes in oil and gas prices upon our revenues as described above under
" -- Liquidity and Capital Resources -- Financial Instruments."
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<PAGE> 28
BUSINESS AND PROPERTIES
Callon has been engaged in the exploration, development, acquisition and
production of oil and gas properties in the Gulf Coast region since 1950. Our
properties and operations are geographically concentrated in the offshore waters
of the Gulf of Mexico where we have substantial experience. We have historically
grown our reserves and production by focusing primarily on low to moderate risk
exploration and acquisition opportunities in the shallow Miocene and outer
continental shelf ("OCS") areas of the Gulf of Mexico. Over the last several
years, we have expanded our areas of exploration to include the deep water area
(900 to 5,500 feet of water) of the Gulf of Mexico. In September 1998, we
announced our first deep water discovery on our Boomslang prospect. Since the
Boomslang discovery, we have drilled two additional deep water discoveries on
our Habanero and Medusa prospects.
The following table provides information about our estimated net proved
reserves in these areas as of July 1, 1999. The information in this table does
not include our Medusa discovery which we announced in September 1999.
<TABLE>
<CAPTION>
PERCENT
ESTIMATED NET PROVED RESERVES DISCOUNTED TOTAL
------------------------------ PRESENT DISCOUNTED
PRIMARY GAS OIL TOTAL VALUE PRESENT
AREA NAME OPERATOR (MMCF) (MBBLS) (MMCFE) ($000) VALUE
- --------- ---------- -------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
SHALLOW MIOCENE AREA:
Mobile Block 864 Area............. Callon 52,162 -- 52,162 $ 63,018 34.2%
Chandeleur Block 40............... Callon 3,674 -- 3,674 3,085 1.7%
Other............................. Callon 1,236 -- 1,236 701 0.3%
------- ------ ------- -------- ------
Total................... 57,072 -- 57,072 66,804 36.2%
------- ------ ------- -------- ------
OCS AREA:
BRETON SOUND:
Main Pass 26/SL 15827............. Callon 5,054 361 7,220 8,207 4.5%
Main Pass 31/SL 12002............. Callon 1,527 31 1,713 2,548 1.4%
Main Pass 36/SL 14964 Garfield.... Callon 4,171 161 5,137 7,682 4.1%
Other Breton Sound................ Callon 686 214 1,970 1,897 1.0%
------- ------ ------- -------- ------
Total Breton Sound........ 11,438 767 16,040 20,334 11.0%
------- ------ ------- -------- ------
OTHER OCS:
High Island Block A-494 Snapper... PetroQuest 4,944 -- 4,944 7,713 4.2%
Eugene Island Block 335........... Murphy 2,892 169 3,906 6,444 3.5%
Vermilion Block 130............... Murphy 1,172 4 1,196 1,257 0.7%
------- ------ ------- -------- ------
Total Other OCS........... 9,008 173 10,046 15,414 8.4%
------- ------ ------- -------- ------
Total................... 20,446 940 26,086 35,748 19.4%
------- ------ ------- -------- ------
DEEP WATER AREA:
Ewing Bank Block 994 Boomslang.... Murphy 8,282 4,601 35,888 21,594 11.7%
Garden Banks Block 341 Habanero... Shell 12,547 6,393 50,905 44,680 24.3%
------- ------ ------- -------- ------
Total................... 20,829 10,994 86,793 66,274 36.0%
------- ------ ------- -------- ------
OTHER AREAS......................... Various 5,302 1,093 11,860 15,534 8.4%
------- ------ ------- -------- ------
Total................... 103,649 13,027 181,811 $184,360 100.0%
======= ====== ======= ======== ======
</TABLE>
SHALLOW MIOCENE AREA
In the shallow Miocene area, we explore for gas deposits using 3-D and
conventional 2-D seismic technology, as well as a proprietary high-resolution
2-D seismic technology which better defines reservoir thickness and continuity.
We have an average working interest in productive wells in the shallow Miocene
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<PAGE> 29
area of 83.3%, all of which we operate. Since 1996, we have drilled four gross
(3.7 net) exploration wells, of which two gross (2.0 net) were productive, and
two gross (1.5 net) development wells, both of which were productive. We have
acquired an extensive infrastructure of production platforms, gathering systems
and pipelines located in our shallow Miocene area. These facilities reduce the
development costs of our successful wells and reduce the time necessary to begin
production from successful wells. In 1997, we also acquired 52.5 Bcf of
estimated net proved reserves in the Mobile Block 864 area for a total
acquisition cost of $48.7 million. We currently have an inventory of three
exploration prospects in this area.
We own approximately 110,000 gross (94,000 net) acres in 18 federal blocks
and various state leases in the shallow Miocene area, and have an average 83.3%
net working interest in 21 producing wells which had average net daily
production of 24.2 MMcf during the first half of 1999. Since 1996, we have
acquired 3,000 miles of seismic data in this area.
The following is a description of the areas in which we have significant
activities in the shallow Miocene area.
Mobile Block 864 Area. The Mobile Block 864 area is located offshore
Alabama in federal waters. During 1997, we consummated four acquisitions of
producing properties and developed and undeveloped acreage in this area for
a total of $48.7 million. In June 1999, we acquired additional interests in
the area in exchange for a production payment requiring us to deliver 7.6
Bcf of gas over the next three and one quarter years. In total, we own an
average 81.1% working interest in ten blocks. Production from a reservoir
that underlies four of the blocks has been unitized. We now own a 66.4%
working interest in the four well unit and the unit production facilities.
We also own a 100% working interest in three additional producing wells in
this area. We are the operator of the Mobile Block 864 unit. Estimated net
proved reserves at July 1, 1999, including the Murphy transaction which
closed in June 1999, were 52.2 Bcf with a discounted present value of $63.0
million. Net average daily production during the first half of 1999 was
14.1 MMcf.
Chandeleur Block 40. Chandeleur Block 40 is located offshore Louisiana
in federal waters. In December 1995, we acquired an additional working
interest in Chandeleur Block 40, increasing our interest to 52.3%. When we
assumed operations of the field, two wells were producing 5.5 MMcf per day
of gas from the 3,800-foot sand. In February 1996, we shut-in one well and
successfully reworked the other and increased average field production to
10.5 MMcf per day of gas. During the fourth quarter of 1996, we drilled a
development well in the field. The well resulted in a field extension which
added 5.0 Bcf in estimated net proved reserves as of December 31, 1996. We
are the operator of Chandeleur Block 40. Estimated net proved reserves at
July 1, 1999 were 3.7 Bcf with a discounted present value of $3.1 million.
Net average daily production during the first half of 1999 was 2.8 MMcf.
OUTER CONTINENTAL SHELF AREA
We explore for oil and gas deposits in the OCS area of the Gulf of Mexico
using the latest in 3-D seismic technology. The wells drilled in this area are
more expensive than the shallow Miocene wells and target larger oil and gas
deposits. Our weighted average working interest in productive wells in the OCS
area is 65.4%. Since 1996, we have drilled 14 gross (6.0 net) exploration wells
in this area, of which six gross (3.3 net) were productive. We also drilled
three gross (1.4 net) development wells, all of which were successful, and we
currently have one gross (0.8 net) exploration well in progress. We currently
have an inventory of 22 exploration prospects in this area, 14 of which we
expect to drill before year-end 2000.
We own approximately 169,000 gross (65,000 net acres) in 32 federal blocks
and various state leases in the OCS area, including the Breton Sound, and have
an average 75% working interest in 19 producing wells which during the first
half of 1999 had average net daily production of 14.2 MMcfe. Since 1996, we have
acquired 450 square miles of 3-D seismic data in this area.
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<PAGE> 30
The following is a description of the current areas in which we have
activities in the OCS.
Breton Sound Area
The Breton Sound area, located in Louisiana state waters, has been a
significant operating area for us since 1997. We have acquired an extensive
infrastructure of pipelines, platforms and other production facilities in this
area. We own an 84.2% weighted average working interest in 13 wells in this
area, all of which we operate, producing from depths of between 6,000 and 13,000
feet. Nine of these wells are burdened by an 80.8% net profits interest held by
an institutional investor. During the second quarter of 1999, net average daily
production from this area was 12.1 MMcfe. Our Garfield well commenced production
in July 1999.
The following is a description of several of our properties in the Brenton
Sound area:
Main Pass 26/SL 15827. We negotiated a farm-in agreement in 1998 for a
97.0% working interest after identifying a prospect on the Main Pass 26
Block based upon a seismic survey we completed in 1996. In August 1998, we
drilled a well to a depth of 10,450 feet. The SL 15827 well was producing
during the second quarter at a net average daily rate of 3.8 MMcf and 193
Bbls of oil. Estimated net proved reserves attributable to this well as of
July 1, 1999 were 7.2 Bcfe with a discounted present value of $8.2 million.
We operate this well.
Main Pass 31/SL 12002. Based upon a 1996 seismic survey that we
completed, we negotiated two separate farm-in agreements for a 100.0%
working interest covering a prospect on Main Pass Block 31. In August 1997,
the SL 12002 was drilled to a vertical depth of 10,900 feet. We completed
the well and placed it on production in December 1997 after flowlines were
laid to a facility we operate at Main Pass Block 32. The well produced 1.9
Bcf and 72.0 MBbls of condensate before being recompleted in the fourth
quarter of 1998. The well was brought back on-line during the first quarter
of 1999 and produced during the second quarter at net average daily rates
of 4.7 MMcf and 118 Bbls per day. Estimated net proved reserves
attributable to this well as of July 1, 1999 were 1.7 Bcfe with a
discounted present value of $2.5 million. We operate this well.
Main Pass 36/SL 14964 Garfield. We acquired a 50.0% working interest
in a prospect on Main Pass Block 36 from Conoco in July 1998. In August
1998, we completed the Garfield well, which has 40 feet of net gas pay in
three zones from 13,300 feet to 16,500 feet. Production from Garfield began
in July 1999, and averaged a net 3.7 MMcf per day and 134 Bbls of oil in
August 1999. Estimated net proved reserves attributable to this well as of
July 1, 1999 were 5.1 Bcfe with a discounted present value of $7.7 million.
We operate this well.
Other OCS Areas
In 1997 we expanded our operations in the OCS area beyond Breton Sound
primarily through an exploration joint venture with Murphy Exploration and
Production, Inc. Since 1996, we have generally limited our working interests in
these prospects to 25.0%. Recently, however, we have sought to increase our
interests in these prospects and, in some cases, acquire operations. Estimated
net proved reserves at July 1, 1999 were 10.0 Bcfe with a discounted present
value of $15.4 million. Net average daily production during the second quarter
of 1999 was 4.4 MMcfe. The following is a description of several of the
significant properties we own in the OCS area outside of Breton Sound.
High Island Block A-494 Snapper. In January 1999, we announced a
discovery on our Snapper prospect, which was drilled to a total depth of
8,800 feet. We own a 50.0% working interest in this well, which we
purchased in 1998 from PetroQuest Energy Inc., the operator. The well began
production in July 1999, and averaged a net of 6.1 MMcf per day in August
1999. Estimated net proved reserves attributable to this well at July 1,
1999 were 4.9 Bcf with a discounted present value of $7.7 million.
Eugene Island Block 335. In 1997, we drilled three wells on Eugene
Island Block 335, which we acquired in an OCS lease sale. We own a 20.0%
working interest in the wells, which are operated by
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<PAGE> 31
Murphy. During the second quarter of 1999, the three wells produced at a
net average daily rate of 4.1 MMcfe. Estimated net proved reserves
attributable to these wells at July 1, 1999 were 3.9 Bcfe with a discounted
present value of $6.4 million.
Vermilion Block 130. In March 1998, we drilled a successful well on
this block, which we acquired in an OCS lease sale, to a total depth of
14,134 feet. We own a 25.0% working interest in this well, which is
operated by Murphy. During the second quarter of 1999, the well produced at
a net average daily rate of 325 Mcfe from one of three proved zones.
Estimated net proved reserves attributable to this well at July 1, 1999
were 1.2 Bcfe with a discounted present value of $1.3 million.
DEEP WATER AREA
We allocate a portion of our capital expenditure budget to the exploration
of deep water regions in the Gulf of Mexico. These wells are expensive to drill
and complete and target large reserve deposits. These wells are usually located
far from production facilities and may require long lead times to construct
pipelines and other facilities necessary to begin producing reserves we
discover. To reduce the risks associated with the high cost of these wells, we
explore these prospects with experienced joint venture partners, including Shell
Deepwater Development, Inc., Vastar Resources, Inc. and Murphy Exploration and
Production, Inc. as operators. We have drilled three gross (0.6 net) exploration
wells in our deep water area, all of which were successful. In September 1998,
we announced our first deep water discovery on our Boomslang prospect which was
followed in February 1999 with a discovery on our Habanero prospect. These
discoveries represent the largest discoveries in our history and have added
estimated net proved reserves of 86.8 Bcfe at July 1, 1999. In September 1999,
we announced a discovery on our Medusa prospect. We currently have an inventory
of 16 deep water exploration prospects, five of which we expect to drill before
year-end 2000.
We own approximately 132,000 gross (24,000 net) acres in 23 blocks in the
deep water areas of the Gulf of Mexico. The following is a description of the
three deep water prospects which have been drilled to date, all of which were
successful and represent the largest discoveries in our history.
The following is a description of several of our significant properties in
the deep water area.
Ewing Bank Block 994 Boomslang. In September 1998, we announced a
discovery on our Boomslang prospect which we acquired in an OCS lease sale.
This well was drilled in 900 feet of water to a total depth of 13,200 feet.
We own a 35.0% working interest in the well, which is operated by Murphy.
Estimated net proved reserves at July 1, 1999 were 35.9 Bcfe, with a
discounted present value of $21.6 million. Prior to designing production
facilities for Boomslang, we plan to drill the Sidewinder prospect. See
"-- Exploration and Development Activities -- Deep Water Area" for a
description of the Sidewinder prospect.
Garden Banks Block 341 Habanero. In February 1999, we announced a
discovery on our Habanero prospect which we acquired from Shell in exchange
for other interests we held on the block. This well was drilled in 2,000
feet of water to a total depth of 21,158 feet. We own an 11.3% working
interest in the well, which is operated by Shell. Estimated net proved
reserves at July 1, 1999 were 50.9 Bcfe, with a discounted present value of
$44.7 million. Prior to designing production facilities for Habanero, we
plan to drill the South Moccasin prospect. See "Exploration and Development
Activities -- Deep Water Area," for a description of the South Moccasin
prospect.
Mississippi Canyon 538/582 Medusa. In September 1999, we announced a
discovery at our Medusa prospect in Mississippi Canyon Block 582. Two
intervals with over 120 feet of total pay were logged after drilling to a
measured depth of 16,241 feet. The prospect is in 2,100 feet of water. We
own a 15.0% working interest in the prospect and Murphy, with a 60.0%
working interest, is the operator. British-Borneo Petroleum, Inc. owns the
remaining 25.0%.
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<PAGE> 32
OTHER AREAS
We own various small royalty and working interests in several onshore
areas, which as of July 1, 1999 had total net proved reserves of 11.9 Bcfe with
a discounted present value of $15.5 million. Over 50.0% of these reserves and
their related discounted present value were attributable to our interest in the
Big Escambia Creek gas field located in south Alabama which is operated by
Exxon.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following is a summary of our anticipated drilling plans through 2000.
We continually review our drilling plans in light of changing circumstances.
Factors which may cause us to change our drilling plans are described under
"Risk Factors."
Deep Water Area
We currently have an inventory of 16 exploration prospects in this area. We
expect to begin drilling two of these prospects, Chin Music and Anvil, before
year-end 1999 and three of these prospects, South Moccasin, Moccasin and
Sidewinder, before year-end 2000. Total estimated gross drilling costs are
$104.6 million ($15.4 million net) for these five wells. Costs to complete the
wells will depend on the reserves discovered and the decisions made by us and
our partners regarding the appropriate production facilities to construct.
Chin Music. Chin Music is located on Mississippi Canyon Blocks 378/379
within the well-established Lena-Cognac depositional fairway. The water depth is
4,500 feet and the test well will target potential reserves down to 18,500 feet.
The test well is scheduled to begin drilling late in the fourth quarter of 1999.
We own a 21.4% working interest in the prospect and Murphy will be the operator.
Estimated net costs to drill this well are $5.9 million.
Anvil. Anvil is located in 5,500 feet of water on Mississippi Canyon Blocks
815/816. We own a 10.0% working interest in this prospect which is scheduled to
be drilled in 2000. We are targeting reserves at a depth of approximately 17,250
feet. Vastar Resources, Inc. is the operator of this well. Estimated net costs
to drill this well are $2.7 million.
South Moccasin. Prior to designing production facilities for the Habanero
prospect on Garden Banks Block 341, we plan to drill the South Moccasin
prospect, located in 1,800 feet of water on Garden Banks Blocks 297 adjacent to
our Habanero discovery. We own a 12.5% working interest in this prospect which
is scheduled to be drilled in 2000. We are targeting reserves at a depth of
approximately 22,000 feet. Estimated net costs to drill this well are $2.5
million. Murphy is the operator of this prospect.
Moccasin. The Moccasin prospect located on Garden Bank Blocks 253 and 297
in a water depth of approximately 1,825 feet will be tested after reaching total
depth on the South Moccasin prospect. Current plans are to sidetrack from the
South Moccasin well bore to test for prospective reserves at depths as low as
17,000 feet. We have a 12.5% working interest in the prospect and net costs to
drill the sidetrack are estimated to be $1.3 million. Murphy is the operator of
this prospect.
Sidewinder. Prior to designing production facilities for the Boomslang
prospect on Ewing Bank Block 994, we plan to drill the Sidewinder prospect,
located in 1,200 feet of water on Ewing Bank Block 995 and Green Canyon Blocks
24 and 25 immediately to the southeast of Boomslang. We own a 15.0% working
interest in this prospect which is scheduled to be drilled in the fourth quarter
of 1999. We are targeting reserves at a depth of approximately 16,000 feet.
Murphy is the operator of this well. Estimated net costs to drill this well are
$3.0 million.
OCS Area
We currently have an inventory of 22 exploration prospects in this area. We
expect to drill five of these prospects before year-end 1999, and an additional
nine prospects during 2000. Total estimated gross drilling costs for these 14
wells through 2000 are $57.7 million ($22.9 million net).
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<PAGE> 33
South Marsh Island Block 261 (Shallow). We currently have two shallow
drilling prospects on South Marsh Island Block 261, which are located in 30 feet
of water. We expect to begin drilling the first of these three wells in the
fourth quarter of 1999 for estimated costs of $2.3 million per well. We own a
100.0% working interest in and will operate these wells, but we may bring in an
industry partner and reduce our interest to approximately 50.0%. The wells will
target reserve deposits at 7,500 feet.
South Marsh Island Block 261 (Deep). The first shallow test well on South
Marsh Island 261 will also test a reserve target at 11,000 feet. It will cost an
additional $2.4 million to drill to this deeper target. We will operate this
well and we have a 100% working interest.
East Cameron Block 275. We expect to drill a well on this prospect, in 160
feet of water offshore Louisiana, in the fourth quarter of 1999. Net costs to
drill this well, which is targeting reserve deposits at approximately 8,000
feet, are estimated to be $2.2 million. We have increased our 25.0% working
interest to 100.0% by negotiating a farm-in agreement. We will be the operator.
Ship Shoal Blocks 319/320 (Shallow). We expect to drill a well on this
prospect, located in 300 feet of water offshore Louisiana, in the first quarter
of 2000. Net costs to drill this well, which is targeting reserve deposits at
9,000 feet, are estimated to be $3.2 million. We have negotiated a farm-in
agreement under which we will own a 100% working interest in the shallow rights
and we will be the operator.
Ship Shoal Blocks 319/320 (Deep). Ship Shoal Blocks 319/320 also contain a
deeper prospect at approximately 14,000 feet which we have scheduled to begin
drilling before year-end 1999. We own a 15% working interest and our share of
the estimated drilling costs is $1.1 million. Murphy will be the operator of
this well.
In addition, we drilled our Parodi prospect located on Main Pass Block 32,
SL/16429 to a total depth of 15,305 feet and encountered a potentially
productive reservoir. Completion efforts during 1997 and 1998 encountered
mechanical difficulties. Based on additional seismic data, we plan to drill
during the fourth quarter of 1999 from the existing well bore to a higher
structural location in the reservoir. We currently own a 75.0% working interest.
We are seeking an industry partner to participate in the drilling operations
estimated to cost $2.9 million gross. We expect to operate the well and retain a
50% working interest.
Shallow Miocene Area
We currently have an inventory of three exploration prospects in this area.
We currently have not scheduled any drilling activities for the shallow Miocene
area because of production capacity constraints at the Mobile Block 864 unit
facilities. We expect to drill these prospects as production capacity becomes
available.
Mobile Block 953 #2. This shallow Miocene prospect was drilled to a total
depth of 2,250 feet in early July 1999 in 70 feet of water. The well was
determined to be non-commercial and was plugged. The prospect is currently being
reevaluated. We own a 100.0% working interest in the prospect and are the
operator.
Mobile Block 908 #4. This shallow Miocene prospect is located in 70 feet of
water and is adjacent to our Mobile Block 864 unit through which production
would be handled. Net costs to drill this prospect will be $0.9 million. We own
an 89.0% working interest in the prospect, which will target reserve deposits at
2,250 feet. We will be the operator of this well.
OCS Lease Sales
In March 1999, we, along with our joint venture partners, bid on 13 deep
water blocks and were the apparent high bidder on nine blocks. Eight of the nine
blocks have been awarded and one block was rejected by the MMS. Our net cost to
acquire these eight blocks was $3.4 million.
In August 1999, we along with our joint venture partners, were the apparent
high bidder on six blocks. Two of the six blocks have been awarded to date. Our
net costs to acquire these six blocks will be $646,000.
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<PAGE> 34
OIL AND GAS RESERVES
The following table sets forth certain information about our estimated net
proved reserves as of the dates set forth below. These estimates were prepared
by Huddleston & Co., Inc., our independent reserve engineers.
<TABLE>
<CAPTION>
DECEMBER 31,
JULY 1, --------------------------------
1999 1998 1997 1996
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Proved developed:
Oil (MBbls)................................... 1,964 1,774 2,976 3,385
Gas (MMcf).................................... 82,557 76,895 88,010 49,491
Proved undeveloped:
Oil (MBbls)................................... 11,063 5,124 426 434
Gas (MMcf).................................... 21,092 11,135 728 933
Total proved:
Oil (MBbls)................................... 13,027 6,898 3,402 3,819
Gas (MMcf).................................... 103,649 88,030 88,738 50,424
Estimated future net cash flows before income
taxes (000s).................................. $300,042 $152,552 $209,260 $216,154
======== ======== ======== ========
Discounted present value (000s)................. $184,360 $ 99,751 $136,448 $160,171
======== ======== ======== ========
</TABLE>
Huddleston & Co., Inc., our independent reserve engineers, prepared the
estimates of the proved reserves and the future net cash flows (and present
value thereof) attributable to such proved reserves. Reserves were estimated
using oil and gas prices and production and development costs in effect on
December 31 of 1996, 1997 and 1998 and on July 1, 1999, without escalation, and
were otherwise prepared in accordance with the SEC regulations regarding
disclosure of oil and gas reserve information.
There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond our control or the control of the
reserve engineers. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner, and the accuracy of any reserve or cash flow estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Estimates by different engineers often vary, sometimes
significantly. In addition, physical factors, such as the results of drilling,
testing and production subsequent to the date of an estimate, as well as
economic factors, such as an increase or decrease in product prices that renders
production of such reserves more or less economic, may justify revision of such
estimates. Accordingly, reserve estimates are different from the quantities of
oil and gas that are ultimately recovered.
We have not filed any reports with other federal agencies which contain an
estimate of our net proved oil and gas reserves.
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<PAGE> 35
MANAGEMENT
INFORMATION ABOUT OUR DIRECTORS AND EXECUTIVE OFFICERS
The following is information about our directors and executive officers as
of September 30, 1999.
<TABLE>
<CAPTION>
POSITION
NAME AGE SINCE PRESENT POSITION
- ---- --- -------- ----------------
<S> <C> <C> <C>
John S. Callon........................ 79 1994 Director, Chairman of the Board
Fred L. Callon........................ 49 1994 Director, President; Chief Executive Officer
Dennis W. Christian................... 53 1994 Director, Senior Vice President; Chief
Operating Officer
John S. Weatherly..................... 47 1994 Senior Vice President and Chief
Financial Officer
James O. Bassi........................ 45 1997 Vice President; Controller
Thomas E. Schwager.................... 48 1997 Vice President
H. Michael Tatum...................... 70 1994 Vice President; Secretary
Kathy G. Tilley....................... 54 1996 Vice President
Stephen F. Woodcock................... 48 1997 Vice President
Rodger W. Smith....................... 50 1999 Treasurer
Leif Dons............................. 49 1999 Director
Robert A. Stanger..................... 59 1995 Director
John C. Wallace....................... 61 1994 Director
B. F. Weatherly....................... 55 1994 Director
Richard O. Wilson..................... 69 1995 Director
</TABLE>
The following is a brief description of the background and principal
occupation of each director and executive officer:
JOHN S. CALLON is our Chairman of the Board of Directors. Effective January
2, 1997, John S. Callon resigned as our Chief Executive Officer, a position he
had held since 1980. Mr. Callon founded our company in 1950, and has held an
executive office with us since that time. He has served as a director of the
Mid-Continent Oil and Gas Association and as the President of the Association's
Mississippi-Alabama Division. He has also served as Vice President for
Mississippi of the Independent Petroleum Association of America. He is a member
of the American Petroleum Institute. Mr. Callon is the uncle of Fred L. Callon.
FRED L. CALLON is our President and Chief Executive Officer. Prior to
January 1997, he was our President and Chief Operating Officer, a position which
he had held since 1984. Before that, he was employed by us in various positions
since 1976. He graduated from Millsaps College in 1972 and received his M.B.A.
degree from the Wharton School of Finance in 1974. Following graduation and
before joining us, he was employed by Peat, Marwick, Mitchell & Co., certified
public accountants. He is a certified public accountant and is a member of the
American Institute of Certified Public Accountants and the Mississippi Society
of Certified Public Accountants. He is the nephew of John S. Callon.
DENNIS W. CHRISTIAN is our Senior Vice President and Chief Operating
Officer. Prior to January 1997, he was our Senior Vice President of Operations
and Acquisitions and had held that or similar positions with us since 1981.
Prior to joining us, he was resident manager in Stavanger, Norway for Texas
Eastern Transmission Corporation. Mr. Christian received his B.S. degree in
petroleum engineering in 1969 from Louisiana Polytechnic Institute. His previous
experience includes five years with Chevron U.S.A. Inc.
JOHN S. WEATHERLY is our Senior Vice President and Chief Financial Officer.
Prior to April 1996, he was our Vice President, Chief Financial Officer and
Treasurer and had held those positions since 1983. Prior to joining us in 1980,
he was employed by Arthur Andersen LLP as audit manager in the Jackson,
Mississippi office. He received his B.B.A. degree in accounting in 1973 and his
M.B.A. degree in 1974 from the University of Mississippi. He is a certified
public accountant and a member of the American
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<PAGE> 36
Institute of Certified Public Accountants and the Mississippi Society of
Certified Public Accountants. John S. Weatherly and B. F. Weatherly are
brothers.
JAMES O. BASSI is our Vice President and Controller. Prior to being
appointed to that position in November 1997, he was our Corporate Controller
from June 1997 and prior thereto was our manager of the accounting department of
Callon and Callon Petroleum Operating. Mr. Bassi has been employed by Callon and
its predecessors for over ten years. Prior to his employment with us, he was
employed by Arthur Andersen LLP. He received his B.S. degree in accounting in
1976 from Mississippi State University. He is a member of the American Institute
of Certified Public Accountants and the Mississippi Society of Certified Public
Accountants.
THOMAS E. SCHWAGER is our Vice President of Engineering and Operations.
Prior to being appointed to that position in November 1997, he had held
engineering positions with us since 1981. Prior to joining us, Mr. Schwager held
various engineering positions with Exxon Company USA in Louisiana and Texas. He
received his B.S. degree in petroleum engineering from Louisiana State
University in 1972. He is a registered professional engineer in the state of
Louisiana and is a member of the Society of Petroleum Engineers.
H. MICHAEL TATUM is our Vice President and Secretary, and is responsible
for management of administrative matters. Mr. Tatum has held this position with
us since 1976 and has been employed by us since 1969. He graduated from Southern
Methodist University in 1967 and is a member of the American Society of
Corporate Secretaries and the Society for Human Resource Management.
KATHY G. TILLEY is our Vice President of Acquisitions and New Ventures, a
position she has held since April 1996. She was first employed by us in December
1989 as manager of acquisitions and prior thereto, held that or similar
positions as a consultant to us since 1981. Ms. Tilley received her B.A. degree
in economics from Louisiana State University in 1967.
STEPHEN F. WOODCOCK is our Vice President of Exploration. He was appointed
to that position in November 1997. He has been employed by us since 1995,
serving as manager of geology and geophysics. Before that, he was manager of
geophysics for CNG Producing Company and division geophysicist for Amoco
Production Company. Mr. Woodcock received his Masters degree in geophysics from
Oregon State University in 1975.
RODGER W. SMITH is our Treasurer. Prior to being appointed to that position
in April, 1999, he was our manager of budget and analysis. Before that, Mr.
Smith was manager of exploration and production accounting and has been employed
by Callon and its predecessors since 1983. Prior to his employment with us, he
was employed by International Paper Company as a plant controller. He received
his B.S. degree in accounting from the University of Southern Mississippi in
1973.
LEIF DONS has since 1997 been Senior Vice President, Business Development
of Fred. Olsen Energy ASA, a publicly held Norwegian company engaged in the
offshore energy service industry. From 1992 until 1997, Mr. Dons was employed by
Kvaerner ASA in various positions, including the fields of international
operations and the commercialization of new technology, and as resident country
manager responsible for Israel and Palestine. From 1983 until 1991, he served as
the managing director of Norwegian Oil Consortium A/S & Co., an oil company with
producing properties in Norway. He negotiated the sale of that company in 1991.
From 1973 until 1983, Mr. Dons held various positions as an analyst, staff
engineer and economist at the Pulp and Paper Research Institute, Norway and Saga
Petroleum ASA. Mr. Dons received a Master of Science degree in engineering from
the Norwegian Institute of Technology in 1973.
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
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<PAGE> 37
economics from Princeton University in 1961. Mr. Stanger is a member of the
National Association of Securities Dealers and the New York Society of Security
Analysts.
JOHN C. WALLACE is a Chartered Accountant having qualified with Coopers and
Lybrand in Canada in 1963, after which he joined Baring Brothers & Co., Limited
in London, England. For more than the last eleven years, he has served as
Chairman of Fred. Olsen Ltd., a London-based corporation which he joined in
1968, and which specializes in the business of shipping and property
development. He is a director of Fred. Olsen Energy ASA, a publicly held
Norwegian service company engaged in the offshore energy service industry;
Harland & Wolff PLC, Belfast, a shipbuilding yard for the offshore oil and gas
industry; and Ganger Rolf ASA and Bonheur ASA, Oslo, both publicly-traded
shipping companies. He is also an executive officer of NOCO Management, Ltd., a
general partner of NOCO Enterprises, L.P. and of other companies associated with
Fred. Olsen Interests.
B. F. WEATHERLY is a principal of Amerimark Capital Group, Houston, Texas,
an investment banking firm and a general partner of CapSource Fund, L. P.,
Jackson Mississippi, an investment fund. He is an executive officer of NOCO
Management Ltd., the general partner of NOCO Enterprises, L.P. Prior to
September 1996, he was Executive Vice President, Chief Financial Officer and a
director of Belmont Constructors, Inc., a Houston, Texas-based industrial
contractor formerly associated with Fred. Olsen Interests. He holds a Master of
Accountancy degree from University of Mississippi. He has previously been
associated with Arthur Andersen LLP, and has served as a Senior Vice President
of Weatherford International, Inc. B. F. Weatherly and John S. Weatherly are
brothers.
RICHARD O. WILSON is an Offshore Consultant. In his 42 years of working in
offshore drilling and construction, he spent two years with Zapata Offshore and
21 years with Brown & Root, Inc. working in various managerial capacities in the
Gulf of Mexico, Venezuela, Trinidad, Brazil, the Netherlands, the United Kingdom
and Mexico. He was a director and senior group vice president of Brown & Root,
Inc. and senior vice president of Halliburton, Inc. For the last 18 years he has
been associated with the Fred. Olsen Interests where he served as Chairman of
OGC International PLC, Dolphin A/S and Dolphin Drilling Ltd., and Belmont
Constructors, Inc. Since the sale of OGC International PLC to Halliburton, Inc.
in 1997, he has been a consultant to Brown & Root, Inc. on oil and gas projects
in Brazil, Bolivia, Mexico and Ecuador. He holds a B.S. degree in civil
engineering from Rice University. Mr. Wilson is a Fellow in the American Society
of Civil Engineers and a member of the Institute of Petroleum, London, England.
All of our officers and directors are United States citizens, except Mr.
Wallace, who is a citizen of Canada, and Mr. Dons, who is a citizen of Norway.
BENEFICIAL OWNERSHIP OF OUR COMMON AND PREFERRED STOCK
The following table shows the ownership of our common stock and Series A
Preferred Stock by the following:
- our five most highly compensated executive officers;
- all of our directors;
- all of our executive officers and directors as a group; and
- anyone who is known by us to beneficially own 5% or more of our
outstanding common stock or preferred stock.
Based on SEC rules, shares of common stock which an individual or group has
the right to acquire within 60 days pursuant to the exercise of options or
warrants are deemed to be outstanding for the purpose of computing the
percentage ownership of such individual or group. These shares are not deemed to
be outstanding for the purpose of computing the percentage ownership of any
other person shown on this table.
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<PAGE> 38
Unless otherwise indicated, each person named in the following table has
the sole power to vote and dispose of the shares listed next to their name.
Information in the table and accompanying text has been obtained from filings
made with the SEC or, in the case of our directors and executive officers, has
been provided by such individuals. Unless otherwise indicated, the information
provided below is based on information available to us as of September 30, 1999.
<TABLE>
<CAPTION>
COMMON STOCK PREFERRED STOCK
---------------------- ----------------------
NAME AND ADDRESS NUMBER OF NUMBER OF
OF BENEFICIAL OWNERS SHARES PERCENTAGE SHARES PERCENTAGE
-------------------- --------- ---------- --------- ----------
<S> <C> <C> <C> <C>
EXECUTIVE OFFICERS:
John S. Callon.................................. 299,902 3.47% -- --
Fred L. Callon.................................. 791,652 9.09% -- --
Dennis W. Christian............................. 196,185 2.25% -- --
John S. Weatherly............................... 180,660 2.07% -- --
Thomas E. Schwager.............................. 67,652 * -- --
Kathy G. Tilley................................. 127,980 1.48% -- --
NON-EMPLOYEE DIRECTORS:
Leif Dons....................................... 5,000 * -- --
Robert A. Stanger............................... 45,856 * -- --
John C. Wallace................................. 2,009,779 23.36% -- --
B.F. Weatherly.................................. 152,664 1.77% -- --
Richard O. Wilson............................... 73,877 * 1,000 *
ALL DIRECTORS AND EXECUTIVE OFFICERS AS A GROUP
(15 PERSONS).................................... 4,028,244 41.87% 1,000 *
CERTAIN BENEFICIAL OWNERS:
Fred. Olsen Energy ASA.......................... 1,839,386 21.49% -- --
Fred. Olsensgate 2
0152 Oslo, Norway
State Street Research & Management Company...... 827,400 9.67% -- --
One Financial Center, 30th Floor
Boston, Massachusetts 02111-2690
The Guardian Life Insurance Company of
America........................................... 748,060 8.26% 220,000 21.04%
201 Park Avenue South
New York, New York 10003
Brinson Partners, Inc. ......................... 554,000 6.47% -- --
209 South LaSalle
Chicago, Illinois 60604-1295
UBS AG.......................................... 554,000 6.47% -- --
Bahnhofstrasse 45
8021, Zurich, Switzerland
Dimensional Fund Advisors Inc. ................. 505,800 5.91% -- --
1299 Ocean Avenue, 11th Floor
Santa Monica, California 90401
</TABLE>
- ---------------
* Under 1%.
JOHN S. CALLON. The shares beneficially owned by John S. Callon include
105,000 shares held in a family limited partnership and 90,000 shares subject to
options under our 1994 Stock Incentive Plan. The shares beneficially owned by
John S. Callon do not include 58,501 shares owned by John S. Callon's wife over
which he disclaims beneficial ownership.
S-38
<PAGE> 39
FRED L. CALLON. The shares beneficially owned by Fred L. Callon include
268,012 shares held as custodian for certain minor Callon family members; 78,430
shares held as trustee of certain Callon family trusts; 57,748 shares held as
trustee of shares held by the Callon Petroleum Company Employee Savings and
Protection Plan; 80,000 shares subject to options under our 1994 Stock Incentive
Plan and 75,000 shares subject to options under our 1996 Stock Incentive Plan.
The shares beneficially owned by Fred L. Callon do not include 25,037 shares
owned by Fred L. Callon's wife over which he disclaims beneficial ownership. Mr.
Callon's address is 200 North Canal Street, P.O. Box 1287, Natchez, Mississippi
39120.
DENNIS W. CHRISTIAN. The shares beneficially owned by Dennis W. Christian
include 60,000 shares subject to options under our 1994 Stock Incentive Plan and
104,500 shares subject to options under our 1996 Stock Incentive Plan.
JOHN S. WEATHERLY. The shares beneficially owned by John S. Weatherly
include 217 shares held as custodian for his minor children; 60,000 shares
subject to options under our 1994 Stock Incentive Plan and 92,500 shares subject
to options under our 1996 Stock Incentive Plan.
THOMAS E. SCHWAGER. The shares beneficially owned by Thomas E. Schwager
include 20,000 shares subject to options under our 1994 Stock Incentive Plan and
33,200 shares subject to options under our 1996 Stock Incentive Plan.
KATHY G. TILLEY. The shares beneficially owned by Kathy G. Tilley include
30,000 shares subject to options under our 1994 Stock Incentive Plan and 73,000
shares subject to options under our 1996 Stock Incentive Plan.
LEIF DONS. The shares beneficially owned by Leif Dons include 5,000 shares
subject to options under our 1994 Stock Incentive Plan.
ROBERT A. STANGER. The shares beneficially owned by Robert A. Stanger
include 25,000 shares subject to options under our 1994 Stock Incentive Plan and
20,000 shares subject to options under our 1996 Stock Incentive Plan.
JOHN C. WALLACE. The shares beneficially owned by John C. Wallace include
107,297 shares owned by NOCO Enterprises, L.P.; 14,971 shares owned by Fred.
Olsen Ltd.; 1,839,386 shares owned by Fred. Olsen Energy ASA; 25,000 shares
subject to options under our 1994 Stock Incentive Plan and 20,000 shares subject
to options under our 1996 Stock Incentive Plan. See "Fred. Olsen Energy ASA"
below. Mr. Wallace's address is 65 Vincent Square, London, SW1P 2RX, England.
B.F. WEATHERLY. The shares beneficially owned by B.F. Weatherly include
107,297 shares owned by NOCO Enterprises, LP; 25,000 shares subject to options
under our 1994 Stock Incentive Plan and 20,000 shares subject to options under
our 1996 Stock Incentive Plan. See "Fred. Olsen Energy ASA" below.
RICHARD O. WILSON. The shares beneficially owned by Richard O. Wilson
include 26,604 shares held in a family limited partnership; 2,273 shares
issuable upon conversion of 1,000 shares of Series A Preferred Stock held in the
family partnership; 25,000 shares subject to options under our 1994 Stock
Incentive Plan and 20,000 shares subject to options under our 1996 Stock
Incentive Plan.
ALL DIRECTORS AND EXECUTIVE OFFICERS. The shares beneficially owned by all
of our directors and executive officers as a group include 490,000 shares
subject to options under our 1994 Stock Incentive Plan exercisable within 60
days; 570,200 shares subject to options under our 1996 Stock Incentive Plan
exercisable within 60 days; and 148,203 shares awarded as performance shares or
restricted stock which vested in February, 1999.
FRED. OLSEN ENERGY ASA. The following information and the information in
the foregoing table is based on information disclosed on a Schedule 13D dated
August 20, 1997 and as otherwise disclosed to us by Fred. Olsen Energy ASA.
Fred. Olsen Energy ASA has the sole power to vote and the sole power to dispose
of 1,839,386 shares of our common stock. Ganger Rolf ASA, a public joint stock
company
S-39
<PAGE> 40
organized and existing under the laws of the Kingdom of Norway and the owner of
28.81% of the outstanding capital stock of Fred. Olsen Energy ASA and Bonheur
ASA, a public joint stock company organized and existing under the laws of the
Kingdom of Norway and the owner of 28.81% of the outstanding capital stock of
Fred. Olsen Energy ASA, together have the power to direct the vote and
disposition of the shares of our common stock owned by Fred. Olsen Energy ASA.
AS Quatro, a joint stock company organized and existing under the laws of the
Kingdom of Norway and the owner of 1.66% of the outstanding capital stock of
Ganger Rolf ASA and 42.10% of the outstanding capital stock of Bonheur ASA and
AS Cinco, a joint stock company organized and existing under the laws of the
Kingdom of Norway and the owner of 11.99% of the outstanding capital stock of
Ganger Rolf ASA, each disclaims beneficial ownership of the shares of our common
stock owned by Fred. Olsen Energy ASA. John C. Wallace, one of our directors, is
a director of Fred. Olsen Energy ASA and a director of Ganger Rolf ASA, Bonheur
ASA, AS Quatro and AS Cinco and, as a result, may by deemed to share the power
to vote and dispose of, and therefore be a beneficial owner of the shares of
common stock owned by Fred. Olsen Energy ASA. The principal business address and
principal executive offices of Ganger Rolf ASA, Bonheur ASA, AS Quatro and AS
Cinco are located at Fred. Olsensgate 2, 0152 Oslo, Norway.
STATE STREET RESEARCH & MANAGEMENT COMPANY. The following information and
the information in the foregoing table is based upon a Schedule 13G, filed with
the SEC on February 8, 1999 by State Street Research & Management Company. State
Street Research & Management Company has sole voting power with respect to
700,400 shares of common stock and sole dispositive power with respect to all of
the shares it beneficially owns.
THE GUARDIAN LIFE INSURANCE COMPANY OF AMERICA. The following information
and the information in the foregoing table is based upon a Schedule 13G/A, filed
with the SEC on February 11, 1998, by The Guardian Life Insurance Company of
America and certain of its affiliates. The common stock beneficially owned by
The Guardian Life Insurance Company of America includes 500,060 shares issuable
upon conversion of 220,000 shares of Series A Preferred Stock.
BRINSON PARTNERS, INC. AND UBS AG. The following information and the
information in the foregoing table is based on a Schedule 13G, filed with the
SEC on February 11, 1999, by UBS AG and Brinson Partners, Inc. Both UBS AG and
Brinson Partners, Inc. possess shared voting and dispositive power with respect
to the shares beneficially owned by them.
DIMENSIONAL FUND ADVISORS INC. The information in the foregoing table is
based upon a Schedule 13G, filed with the SEC on February 11, 1999, by
Dimensional Fund Advisors Inc.
DESCRIPTION OF CAPITAL STOCK
We are authorized to issue up to 20,000,000 shares of common stock, $0.01
par value. As of September 30, 1999, there were 8,557,906 shares of common stock
issued and outstanding.
Holders of common stock are entitled to one vote per share in the election
of directors and on all other matters submitted to a vote of stockholders.
Holders do not have the right to cumulate their votes in the election of
directors. Holders of common stock have no redemption or conversion rights and
no preemptive or other rights to subscribe for our securities. In the event of
our liquidation, dissolution or winding up, holders of common stock are entitled
to share equally and ratably in all of the assets remaining, if any, after
satisfaction of all our debts and liabilities, and of the preferential rights of
any series of preferred stock then outstanding. The outstanding shares of common
stock are validly issued, fully paid and nonassessable. Holders of common stock
are entitled to receive dividends when, as and if declared by the board of
directors out of funds legally available therefor. American Stock Transfer &
Trust Company is transfer agent and registrar for the common stock.
See "Description of Capital Stock" in the prospectus attached to this
prospectus supplement for a description of matters which may be important to you
regarding our common stock and preferred stock, including the anti-takeover
effects of provisions of Delaware law, our classified board of directors and the
terms of our outstanding Series A Preferred Stock.
S-40
<PAGE> 41
DESCRIPTION OF BANK CREDIT FACILITY AND OTHER INDEBTEDNESS
BANK CREDIT FACILITY
Borrowings under our bank credit facility are secured by mortgages covering
substantially all of our producing oil and gas properties. Currently, the credit
facility provides for a $20 million borrowing base which is adjusted
periodically on the basis of a discounted present value of future net cash flows
attributable to our proved producing oil and gas reserves. We expect our
borrowing base to substantially increase. Under our bank credit facility, the
interest rate is equal to the lender's prime rate plus 0.125% but increases to
prime plus 0.50% if we borrow more than 50% of our borrowing base. At our
option, we may fix the interest rate on all or a portion of the outstanding
principal balance at 1.125% above a defined "Eurodollar" rate for periods up to
six months which increases to 1.5% if we borrow more than 50% of our borrowing
base. The weighted average interest rate for the total debt outstanding at June
30, 1999 was 6.53%. Under the credit facility, a quarterly commitment fee of
0.25% is assessed on the unused portion of the borrowing base which increases to
0.375% if we borrow more than 50% of our borrowing base. We may borrow, pay,
reborrow and repay under the credit facility until October 31, 2000, on which
date we must repay in full all amounts then outstanding.
Borrowings under the bank credit facility are guaranteed by our material
subsidiaries. The bank credit facility has several customary covenants
including, but not limited to, covenants that limit our ability to:
- repurchase capital stock;
- guaranty borrowings or borrow additional funds;
- prepay other indebtedness;
- merge;
- sell property;
- engage in transactions with our affiliates;
- hedge our production; and
- make acquisitions.
We are also required by the bank to maintain several financial ratios and
conditions so that the bank can monitor our financial stability.
OUTSTANDING NOTES
On July 20, 1999, we sold $40 million of 10.25% senior subordinated notes
to the public. Payments of principal, interest and any premium are subordinated
to all of our senior indebtedness. The 10.25% notes are not entitled to any
mandatory sinking fund payment and are subject to redemption at our option at
par plus unpaid interest at any time after March 15, 2001. The 10.25% notes are
listed on the New York Stock Exchange under the symbol "CPE 04."
If a "change of control" occurs, we are obligated to offer to repurchase
the 10.25% notes for 101% of par plus accrued and unpaid interest to the date of
purchase. A change of control is defined as:
- the sale or other disposition of substantially all of our assets;
- the adoption of a plan relating to our liquidation or dissolution;
- the acquisition by any person of beneficial ownership of 50% or more of
the aggregate voting power of our equity securities; or
- the first day on which the majority of our board of directors is not
comprised of directors who were directors on July 20, 1999 or directors
who were nominated by a majority of such directors and their nominees.
S-41
<PAGE> 42
No assurances can be made that we will have sufficient funds available if a
change of control were to occur, to repurchase the 10.25% notes.
On July 31, 1997, we sold $36 million aggregate principal amount of our
10.125% series A senior subordinated notes due September 15, 2002 in a private
placement. On September 10, 1997, we commenced an offer to exchange the notes
for a like principal amount of 10.125% series B senior subordinated notes due
September 15, 2002. The form and terms of the series B notes are identical in
all material respects to the terms of the series A notes, except the series A
notes have certain transfer restrictions and provisions relating to registration
rights. Payments of principal, interest and premium, if any, under the series A
and series B notes are subordinate to all of our existing and future senior
indebtedness. The series A and series B notes are not entitled to the benefit of
any mandatory sinking fund payments and are subject to redemption at anytime on
or after September 15, 2000, at our option, at par plus accrued and unpaid
interest to the date fixed for redemption.
On November 27, 1996, we sold $24.2 million aggregate principal amount of
10% senior subordinated notes due December 15, 2001. Payments of principal,
interest and premium, if any, under these notes are subordinate to all of our
existing and future senior indebtedness. The 10% notes are not entitled to the
benefit of any mandatory sinking fund payments and are subject to redemption at
anytime on or after December 15, 1997, at our option, at par plus accrued and
unpaid interest to the date fixed for redemption.
S-42
<PAGE> 43
UNDERWRITING
The underwriters named below, acting through their representatives, A.G.
Edwards & Sons, Inc., Howard, Weil, Labouisse, Friedrichs Incorporated, Johnson
Rice & Company L.L.C. and Morgan Keegan & Company, Inc. have severally agreed,
subject to the terms and conditions of the underwriting agreement between the
underwriters and us, to purchase from us the respective number of shares of
common stock indicated in the following table at the public offering price less
the underwriting discount set forth on the cover page of this prospectus
supplement.
<TABLE>
<CAPTION>
UNDERWRITERS NUMBER OF SHARES
------------ ----------------
<S> <C>
A.G. Edwards & Sons, Inc. ..................................
Howard, Weil, Labouisse, Friedrichs Incorporated............
Johnson Rice & Company L.L.C................................
Morgan Keegan & Company, Inc. ..............................
---------
Total............................................. 3,200,000
=========
</TABLE>
The underwriting agreement provides that the obligations of the
underwriters are subject to certain conditions precedent and that the
underwriters will purchase all such shares of the common stock if any of the
shares are purchased. The underwriters are obligated to take and pay for all of
the shares of common stock offered by this prospectus supplement, other than
those covered by the over-allotment option described below, if any are taken.
The representatives of the underwriters have advised us that the
underwriters propose initially to offer such shares of common stock to the
public at the public offering price set forth on the cover page of this
prospectus supplement and to certain dealers at such price less a concession not
in excess of $ per share. The underwriters may allow, and such dealers may
re-allow, a concession not in excess of $ per share to certain other
dealers. After the offering, the offering price and other selling terms may be
changed by the underwriters.
We have granted to the underwriters an option, exercisable for 30 days
after the date of this prospectus supplement, to purchase up to an additional
480,000 shares of common stock at the public offering price, less the
underwriting discount, set forth on the cover page of this prospectus
supplement. The underwriters may exercise such option solely to cover
over-allotments, if any, made in connection with the sale of shares of common
stock that the underwriters have agreed to purchase.
To the extent the underwriters exercise such option, the underwriters will
become obligated, subject to certain conditions, to purchase approximately the
same percentage of such additional shares as the number set forth next to such
underwriter's name in the preceding table bears to the total number of shares in
the table, and we will be obligated, pursuant to the option, to sell such
shares, to the underwriters.
Callon, each of its directors and executive officers, and Fred. Olsen
Energy ASA have agreed not to sell or otherwise dispose of any shares of common
stock for a period of 90 days after the date of this prospectus supplement
without the prior written consent of A.G. Edwards & Sons, Inc. A.G. Edwards &
Sons, Inc. may, in its sole discretion, allow any of these parties to dispose of
common stock prior to the expiration of the 90 day period. There are, however,
no agreements between A.G. Edwards & Sons, Inc. and these parties that would
allow them to do so.
The price of the shares of common stock purchased by the underwriters will
be the public offering price set forth on the cover page of this prospectus
supplement less the following discounts, to be paid to the underwriters by
Callon. These amounts are shown assuming both no exercise and full exercise of
the underwriters' option to purchase additional shares of common stock.
<TABLE>
<CAPTION>
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per share......................................... $ $
Total............................................. $ $
</TABLE>
S-43
<PAGE> 44
We expect to incur expenses of approximately $650,000 in connection with
this offering.
We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act.
Until the distribution of the common stock is completed, rules of the SEC
may limit the ability of the underwriters and certain selling group members to
bid for and purchase the common stock. As an exception to these rules, the
underwriters are permitted to engage in certain transactions that stabilize,
maintain or otherwise affect the price of the common stock.
If the underwriters create a short position in the common stock in
connection with the offering, i.e., if they sell a greater aggregate number of
shares of common stock than is set forth on the cover page of this prospectus
supplement, the underwriters may reduce the short position by purchasing shares
of common stock in the open market. This is known as a "syndicate covering
transaction." The underwriters may also elect to reduce any short position by
exercising all or part of the over-allotment option described above.
The underwriters may also impose a penalty bid on certain selling group
members. This means that if the underwriters purchase common stock in the open
market to reduce the selling group members' short position or to stabilize the
price of the common stock, they may reclaim the amount of the selling concession
from the selling group members who sold those shares of common stock as part of
the offering.
In general, purchases of the common stock for the purpose of stabilization
or to reduce a short position could cause the price of the common stock to be
higher than it might be in the absence of such purchases. The imposition of a
penalty bid also may have an effect on the price of the common stock to the
extent that it discourages resales of the common stock.
The underwriters are not obligated to engage in any of the transactions
described above. If they do engage in any of these transactions, they may
discontinue them at any time.
A.G. Edwards & Sons, Inc., Morgan Keegan & Company, Inc. and Howard, Weil,
Labouisse, Friedrichs Incorporated have acted as underwriters of past offerings
by us. The underwriters may perform services for us in the future.
VALIDITY OF THE COMMON STOCK
Our lawyers, Haynes and Boone, LLP, Houston, Texas, will issue opinions
about the validity of the common stock for us. Certain legal matters will be
passed upon for the underwriters by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The audited consolidated financial statements as of December 31, 1998, and
for the three years in the period ended December 31, 1998, included elsewhere in
this prospectus supplement have been audited by Arthur Andersen LLP, independent
public accountants, as indicated in their report with respect thereto, and are
included herein in reliance upon their authority as experts in accounting and
auditing in giving said reports.
The information appearing and incorporated by reference in this prospectus
supplement regarding our quantities of oil and gas and future net cash flows and
the present values thereof from such reserves is based on estimates of such
reserves and present values prepared by Huddleston & Co., Inc., an independent
petroleum and geological engineering firm and are included herein in reliance
upon their authority as experts in estimating reserves and present values.
S-44
<PAGE> 45
GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.
Bcf -- One billion cubic feet of natural gas.
Bcfe -- One billion cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
MBbl -- One thousand Bbls.
Mcf -- One thousand cubic feet of natural gas.
Mcfe -- One thousand cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
MMcf -- One million cubic feet of natural gas.
MMcfe -- One million cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis that one Bbl equals six Mcf.
TERMS USED TO DESCRIBE OUR INTERESTS IN WELLS AND ACREAGE
Gross oil and gas wells or acres -- Our gross wells or gross acres
represent the total number of wells or acres in which we own a working interest
(or, where we do not own a working interest, a royalty interest).
Net oil and gas wells or acres -- Determined by multiplying "gross" oil and
natural gas wells or acres by the working interest (or, where we do not own a
working interest, a royalty interest) that we own in such wells or acres.
TERMS USED TO ASSIGN A PRESENT VALUE TO OUR RESERVES
Standardized measure of proved reserves -- The present value, discounted at
10%, of the pre-tax future net cash flows attributable to estimated net proved
reserves. We calculate this amount by assuming that we will sell the oil and gas
production attributable to the proved reserves estimated in our independent
engineer's reserve report for the prices we received for the production on the
date of the report, unless we had a contract to sell the production for a
different price. We also assume that the cost to produce the reserves will
remain constant at the costs prevailing on the date of the report. The assumed
costs are subtracted from the assumed revenues resulting in a stream of future
net cash flows. Estimated future income taxes using rates in effect on the date
of the report are deducted from the net cash flow stream. The after-tax cash
flows are discounted at 10% to result in the standardized measure of our proved
reserves. The standardized measure of our proved reserves is disclosed in our
financial statements at Note 12.
Discounted present value -- The discounted present value of proved reserves
is identical to the standardized measure, except that estimated future income
taxes are not deducted in calculating future net cash flows. We disclose the
discounted present value without deducting estimated income taxes to provide
what we believe is a better basis for comparison of our reserves to other
producers who may have different tax rates.
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
Proved reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known oil
and natural gas reservoirs under existing economic and operating conditions.
S-45
<PAGE> 46
The Securities and Exchange Commission definition of proved oil and gas
reserves, as set forth in Article 4-10(a)(2) of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (2) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (3) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (4) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
Proved developed reserves -- Proved reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods.
Proved undeveloped reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required.
TERMS WHICH DESCRIBE THE COST TO ACQUIRE OUR RESERVES
Reserve replacement costs -- Our reserve replacement costs compare the
amount we spent to explore for oil and gas and to drill and complete wells
during a period, with the increases in reserves during the period. This amount
is calculated by dividing the net change in our evaluated oil and property costs
during a period by the change in proved reserves plus production over the same
period.
TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES
Reserve life -- A measure of the productive life of an oil and gas property
or a group of oil and gas properties, expressed in years. Reserve life equals
the estimated net proved reserves attributable to a property or group of
properties divided by production from the property or group of properties for
the four fiscal quarters preceding the date as of which the proved reserves were
estimated.
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF OUR OIL AND GAS PROPERTIES
Royalty interest -- A real property interest entitling the owner to receive
a specified portion of the gross proceeds of the sale of oil and natural gas
production or, if the conveyance creating the interest provides, a specific
portion of oil and natural gas produced, without any deduction for the costs to
explore for, develop or produce the oil and natural gas. A royalty interest
owner has no right to consent to or
S-46
<PAGE> 47
approve the operation and development of the property, while the owners of the
working interest have the exclusive right to exploit the mineral on the land.
Working interest -- A real property interest entitling the owner to receive
a specified percentage of the proceeds of the sale of oil and natural gas
production or a percentage of the production, but requiring the owner of the
working interest to bear the cost to explore for, develop and produce such oil
and natural gas. A working interest owner who owns a portion of the working
interest may participate either as operator or by voting his percentage interest
to approve or disapprove the appointment of an operator and drilling and other
major activities in connection with the development and operation of a property.
TERMS USED TO DESCRIBE SEISMIC OPERATIONS
Seismic data -- Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in exploration
for new deposits and to manage or enhance production from known reservoirs. To
gather seismic data, an energy source is used to send sound waves into the
subsurface strata. These waves are reflected back to the surface by underground
formations, where they are detected by geophones which digitize and record the
reflected waves. Computers are then used to process the raw data to develop an
image of underground formations.
2-D seismic data -- 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad area. 2-D
seismic data is collected by a single line of energy sources which reflect
seismic waves to a single line of geophones. When processed, 2-D seismic data
produces an image of a single vertical plane of sub-surface data.
3-D seismic -- 3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey produces a
three dimensional image of the subsurface geology by collecting seismic data
along parallel lines and creating a cube of information that can be divided into
various planes, thus improving visualization. Consequently, 3-D seismic data is
a more reliable indicator of potential oil and natural gas reservoirs in the
area evaluated.
S-47
<PAGE> 48
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets as of December 31, 1998,
December 31, 1997 and June 30, 1999....................... F-3
Consolidated Statements of Operations for Each of the Three
Years in the Period Ended December 31, 1998 and the Six
Months Ended June 30, 1999 and 1998....................... F-4
Consolidated Statements of Stockholders' Equity for Each of
the Three Years in the Period Ended December 31, 1998 and
the Six Months Ended June 30, 1999........................ F-5
Consolidated Statements of Cash Flows for Each of the Three
Years in the Period Ended December 31, 1998 and the Six
Months Ended June 30, 1999 and 1998....................... F-6
Notes to Consolidated Financial Statements.................. F-7
</TABLE>
F-1
<PAGE> 49
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors
of Callon Petroleum Company:
We have audited the accompanying consolidated balance sheets of Callon
Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
1998 and 1997, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Callon Petroleum Company and
subsidiaries, as of December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
/s/ ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 19, 1999
F-2
<PAGE> 50
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ---------------------
1999 1998 1997
----------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 7,334 $ 6,300 $ 15,597
Accounts receivable....................................... 5,287 6,024 12,168
Other current assets...................................... 939 1,924 723
--------- --------- ---------
Total current assets............................... 13,560 14,248 28,488
--------- --------- ---------
Oil and gas properties, full-cost accounting method:
Evaluated properties...................................... 484,202 444,579 398,046
Less accumulated depreciation, depletion and
amortization............................................ (353,144) (345,353) (282,891)
--------- --------- ---------
131,058 99,226 115,155
Unevaluated properties excluded from amortization......... 42,509 42,679 35,339
--------- --------- ---------
Total oil and gas properties....................... 173,567 141,905 150,494
--------- --------- ---------
Pipeline and other facilities, net.......................... 6,021 6,182 6,504
Other property and equipment, net........................... 1,556 1,753 1,938
Deferred tax asset.......................................... 15,989 16,348 1,248
Long-term gas balancing receivable.......................... 224 199 242
Other assets, net........................................... 909 1,017 1,507
--------- --------- ---------
Total assets....................................... $ 211,826 $ 181,652 $ 190,421
========= ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities.................. $ 8,913 $ 11,257 $ 12,389
Deferred revenue in the sale of production payment
interest -- current portion............................. 4,844 -- --
Undistributed oil and gas revenues........................ 2,029 1,720 2,259
Accrued net profits interest payable...................... 250 129 1,121
--------- --------- ---------
Total current liabilities.......................... 16,036 13,106 15,769
--------- --------- ---------
Accounts payable and accrued liabilities to be refinanced... 1,763 3,000 --
Long-term debt.............................................. 99,250 78,250 60,250
Deferred revenue on sale of production payment interest..... 9,671 -- --
Accrued retirement benefits................................. 2,215 2,323 297
Long-term gas balancing payable............................. 491 489 404
--------- --------- ---------
Total liabilities.................................. 129,426 97,168 76,720
--------- --------- ---------
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares
authorized; 1,045,461 shares of Convertible Exchangeable
Preferred Stock, Series A, issued and outstanding at
June 30, 1999 and 1,255,811 and 1,315,500 outstanding at
December 31, 1998 and 1997, respectively, with a
liquidation preference of $26,136,525 at June 30,
1999.................................................... 10 13 13
Common Stock, $.01 par value; 20,000,000 shares
authorized; 8,545,517, 8,178,406 and 7,855,216 shares
outstanding at June 30, 1999, December 1998 and 1997,
respectively............................................ 86 82 79
Treasury stock (98,578 shares at cost).................... (1,177) (915) --
Unearned compensation -- restricted stock................. -- -- (2,232)
Capital in excess of par value............................ 108,296 109,429 106,433
Retained earnings (deficit)............................... (24,815) (24,125) 9,408
--------- --------- ---------
Total stockholders' equity......................... 82,400 84,484 113,701
--------- --------- ---------
Total liabilities and stockholders' equity......... $ 211,826 181,652 $ 190,421
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 51
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED JUNE 30, YEARS ENDED DECEMBER 31,
----------------- ----------------------------
1999 1998 1998 1997 1996
------- ------- -------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales......................... $16,537 $20,322 $ 35,624 $42,130 $25,764
Interest and other........................ 868 903 2,094 1,508 946
------- ------- -------- ------- -------
Total revenues.................... 17,405 21,225 37,718 43,638 26,710
------- ------- -------- ------- -------
Cost and expenses:
Lease operating expenses.................. 3,486 4,089 7,817 8,123 7,562
Depreciation, depletion and
amortization........................... 7,952 10,466 19,284 16,488 9,832
General and administrative................ 2,440 2,732 5,285 4,433 3,495
Interest.................................. 2,471 983 1,925 1,957 313
Accelerated vesting and retirement
benefits............................... -- -- 5,761 -- --
Impairment of oil and gas properties...... -- -- 43,500 -- --
------- ------- -------- ------- -------
Total costs and expenses.......... 16,349 18,270 83,572 31,001 21,202
------- ------- -------- ------- -------
Income (loss) from operations............... 1,056 2,955 (45,854) 12,637 5,508
Income tax expense (benefit).............. 359 1,001 (15,100) 4,200 50
------- ------- -------- ------- -------
Net income (loss)........................... 697 1,954 (30,754) 8,437 5,458
Preferred stock dividends................... 1,386 1,398 2,779 2,795 2,795
------- ------- -------- ------- -------
Net income (loss) available to common
shares.................................... $ (689) $ 556 $(33,533) $ 5,642 $ 2,663
======= ======= ======== ======= =======
Net income (loss) per common share:
Basic..................................... $ (.08) $ .07 $ (4.17) $ .91 $ .46
======= ======= ======== ======= =======
Diluted................................... $ (.08) $ .07 $ (4.17) $ .88 $ .45
======= ======= ======== ======= =======
Shares used in computing net income (loss)
per common share:
Basic..................................... 8,462 8,021 8,034 6,194 5,835
======= ======= ======== ======= =======
Diluted................................... 8,462 8,233 8,034 6,422 5,952
======= ======= ======== ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 52
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
<TABLE>
<CAPTION>
UNEARNED
COMPENSATION CAPITAL IN RETAINED
PREFERRED COMMON TREASURY RESTRICTED EXCESS OF EARNINGS
STOCK STOCK STOCK STOCK PAR VALUE (DEFICIT)
--------- ------ -------- ------------ ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1995......... $13 $58 $ -- $ -- $ 73,955 $ 1,103
Net income........................ -- -- -- -- -- 5,458
Preferred stock dividends......... -- -- -- -- -- (2,795)
Shares issued pursuant to employee
benefit plan................... -- -- -- -- 72 --
--- --- ------- ------- -------- --------
Balances, December 31, 1996......... 13 58 -- -- 74,027 3,766
Net income........................ -- -- -- -- -- 8,437
Sale of common stock.............. -- 19 -- -- 29,249 --
Preferred stock dividends......... -- -- -- -- -- (2,795)
Tax benefits related to stock
compensation plans............. -- -- -- -- 36 --
Shares issued pursuant to employee
benefit and option plan........ -- -- -- -- 392 --
Restricted stock plan............. -- 2 -- (3,153) 2,729 --
Earned portion of restricted
stock.......................... -- -- -- 921 -- --
--- --- ------- ------- -------- --------
Balances, December 31, 1997......... 13 79 -- (2,232) 106,433 9,408
Net income (loss)................. -- -- -- -- -- (30,754)
Preferred stock dividends......... -- -- -- -- 15 (2,779)
Shares issued pursuant to employee
benefit and option plan........ -- -- -- -- 235 --
Employee stock purchase plan...... -- -- -- -- 163 --
Restricted stock plan............. -- 2 -- (2,731) 2,584 --
Earned portion of restricted
stock.......................... -- -- -- 4,963 -- --
Conversion of preferred shares to
common......................... -- 1 -- -- (1) --
Stock buyback plan................ -- -- (915) -- -- --
--- --- ------- ------- -------- --------
Balances, December 31, 1998......... 13 82 (915) -- 109,429 (24,125)
Net income (loss)................. -- -- -- -- -- 697
Preferred stock dividends......... -- -- -- -- 276 (1,387)
Shares issued pursuant to employee
benefit and option plan........ -- -- -- -- 140 --
Employee stock purchase plan...... -- -- -- -- 66 --
Shares surrendered -- restricted
stock plan..................... -- (1) -- -- (1,613) --
Conversion of preferred shares to
common......................... (3) 5 -- -- (2) --
Stock buyback plan................ -- -- (262) -- -- --
--- --- ------- ------- -------- --------
Balances, June 30, 1999
(Unaudited)....................... $10 $86 $(1,177) $ -- $108,296 $(24,815)
=== === ======= ======= ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 53
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
1999 1998 1998 1997 1996
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss).......................... $ 697 $ 1,954 $(30,754) $ 8,437 $ 5,458
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion and amortization... 8,210 10,722 19,791 16,924 10,131
Impairment of oil and gas properties....... -- -- 43,500 -- --
Amortization of deferred production payment
revenue................................. (252) -- -- -- --
Amortization of deferred costs............. 276 318 619 467 114
Deferred income tax expense (benefit)...... 359 1,001 (15,100) 4,200 50
Noncash compensation related to stock
compensation plans...................... 141 1,033 7,583 1,224 72
Changes in current assets and liabilities:
Accounts receivable..................... 737 1,344 6,144 493 (4,332)
Other current assets.................... 985 (430) (1,201) (207) (278)
Current liabilities..................... (1,532) 357 (860) (3,809) 4,049
Change in gas balancing receivable......... (25) 20 43 418 (41)
Change in gas balancing payable............ 2 (52) 85 14 (42)
Change in other long-term liabilities...... (108) -- -- 249 (28)
Change in other assets, net................ (168) (82) (129) (1,073) (830)
-------- -------- -------- -------- --------
Cash provided (used) by operating
activities.............................. 9,322 16,185 29,721 27,337 14,323
-------- -------- -------- -------- --------
Cash flows from investing activities:
Capital expenditures....................... (25,129) (23,733) (64,105) (89,609) (37,637)
Cash proceeds from sale of mineral
interests............................... -- 10,211 9,909 4,450 1,574
Cash proceeds from sale of mineral interest
burdened by a net profits interest...... -- 19,957 -- -- --
-------- -------- -------- -------- --------
Cash provided (used) by investing
activities.............................. (25,129) 6,435 (54,196) (85,159) (36,063)
-------- -------- -------- -------- --------
Cash flows from financing activities:
Change in accrued liabilities for capital
expenditures............................ -- -- (2,396) 3,610 3,346
Change in accounts payable and accrued
liabilities to be refinanced............ (1,237) -- 3,000 -- --
Equity issued related to employee stock
plans................................... 66 249 414 90 --
Purchase of treasury shares................ (262) -- (915) -- --
Payments on debt........................... -- -- -- (49,200) (25,850)
Proceeds from debt issuance................ 21,000 -- 18,000 85,200 50,000
Common stock canceled...................... (1,615) (145) (130) (422) --
Sale of common stock....................... -- -- -- 29,267 --
Increase (decrease) in accrued preferred
stock dividends payable................. -- -- (16) -- 443
Dividends on preferred stock............... (1,111) (1,398) (2,779) (2,795) (2,795)
-------- -------- -------- -------- --------
Cash provided (used) by financing
activities.............................. 16,841 (1,294) 15,178 65,750 25,144
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents................................ 1,034 21,326 (9,297) 7,928 3,404
Cash and cash equivalents:
Balance, beginning of period............... 6,300 15,597 15,597 7,669 4,265
-------- -------- -------- -------- --------
Balance, end of period..................... $ 7,334 $ 36,923 $ 6,300 $ 15,597 $ 7,669
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 54
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION WITH RESPECT TO THE PERIODS ENDING JUNE 30, 1999 AND 1998 IS
UNAUDITED.)
1. ORGANIZATION
Callon Petroleum Company (the "Company") was organized under the laws of
the state of Delaware in March 1994 to serve as the surviving entity in the
consolidation and combination of several related entities (referred to herein
collectively as the "Constituent Entities"). The combination of the businesses
and properties of the Constituent Entities with the Company was completed on
September 16, 1994 (the "Consolidation").
As a result of the Consolidation, all of the businesses and properties of
the Constituent Entities are owned (directly or indirectly) by the Company.
Certain registration rights were granted to the stockholders of certain of the
Constituent Entities. See Note 7.
The Company and its predecessors have been engaged in the acquisition,
development and exploration of crude oil and natural gas since 1950. The
Company's properties are geographically concentrated in Louisiana, Alabama,
Texas and offshore Gulf of Mexico.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Reporting
The Consolidated Financial Statements include the accounts of the Company,
and its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has
subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing,
Inc. All intercompany accounts and transactions have been eliminated. Certain
prior year amounts have been reclassified to conform to presentation in the
current year.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("FAS 133"), Accounting for Derivative
Instruments and Hedging Activities. The Statement establishes accounting and
reporting standards requiring that every derivative instrument, including
certain derivative instruments embedded in other contracts, be recorded in the
balance sheet as either an asset or liability measured at its fair value. FAS
133 is effective for fiscal years beginning after June 15, 2000, with earlier
application permitted. The Company has not yet determined the timing or method
of the adoption of FAS 133 and thus cannot quantify the impact of adoption.
However, the Statement will create volatility in equity through other
comprehensive income.
In June 1997, the Financial Accounting Standards Board issued Statement No.
130 ("FAS 130"), Reporting Comprehensive Income. FAS 130 establishes standards
for reporting and display of comprehensive income and its components in a full
set of general purpose financial statements. FAS 130 was effective for the
Company in 1998. The Company does not have any items of other comprehensive
income.
Also in 1997, the Financial Accounting Standards Board issued Statement No.
131 ("FAS 131"), Disclosures about Segments of an Enterprise and Related
Information. FAS 131 establishes standards for
F-7
<PAGE> 55
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the way that public business enterprises report information about operating
segments in annual financial statements and requires that those enterprises
report selected information about operating segments in interim financial
reports issued to shareholders. The Company has only one operating segment and
thus separate segment disclosure is not required.
Property and Equipment
The Company follows the full-cost method of accounting for oil and gas
properties whereby all costs incurred in connection with the acquisition,
exploration and development of oil and gas reserves, including certain overhead
costs, are capitalized. Such amounts include the cost of drilling and equipping
productive wells, dry hole costs, lease acquisition costs, delay rentals,
interest capitalized on unevaluated leases and other costs related to
exploration and development activities. Payroll and general and administrative
costs capitalized include salaries and related fringe benefits paid to employees
directly engaged in the acquisition, exploration and/or development of oil and
gas properties as well as other directly identifiable general and administrative
costs associated with such activities. Costs associated with unevaluated
properties are excluded from amortization. Unevaluated property costs are
transferred to evaluated property costs at such time as wells are completed on
the properties, the properties are sold or management determines these costs
have been impaired.
Costs of properties, including future development and net future site
restoration, dismantlement and abandonment costs, which have proved reserves and
those which have been determined to be worthless, are depleted using the
unit-of-production method based on proved reserves. If the total capitalized
costs of oil and gas properties, net of amortization, exceed the sum of (1) the
estimated future net revenues from proved reserves at current prices and
discounted at 10% and (2) the lower of cost or market of unevaluated properties
(the full-cost ceiling amount), net of tax effects, then such excess is charged
to expense during the period in which the excess occurs. See Note 8.
Upon the acquisition or discovery of oil and gas properties, management
estimates the future net costs to be incurred to dismantle, abandon and restore
the property using geological, engineering and regulatory data available. Such
cost estimates are periodically updated for changes in conditions and
requirements. Such estimated amounts are considered as part of the full-cost
pool subject to amortization upon acquisition or discovery. Such costs are
capitalized as oil and gas properties as the actual restoration, dismantlement
and abandonment activities take place. As of December 31, 1998 and 1997 and June
30, 1999, estimated future site restoration, dismantlement and abandonment
costs, net of related salvage value and amounts funded by abandonment trusts
(see Notes 7 and 9) were not material.
Depreciation of other property and equipment is provided using the
straight-line method over estimated lives of three to twenty years. Depreciation
of the pipeline and other facilities is provided using the straight-line method
over estimated lives of 15 to 27 years.
Natural Gas Imbalances
The Company follows an entitlement method of accounting for its
proportionate share of gas production on a well by well basis, recording a
receivable to the extent that a well is in an "undertake" position and
conversely recording a liability to the extent that a well is in an "overtake"
position.
Derivatives
The Company uses derivative financial instruments (see Note 6) for price
protection purposes on a limited amount of its future production and does not
use them for trading purposes. Such derivatives are accounted for on an accrual
basis and amounts paid or received under the agreements are recognized as oil
and gas sales in the period in which they accrue.
F-8
<PAGE> 56
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accounts Receivable
Accounts receivable consists primarily of accrued oil and gas production
receivable. The balance in the reserve for doubtful accounts included in
accounts receivable is $38,000, $38,000 and $36,000 at June 30, 1999, December
31, 1998 and 1997, respectively. Net recoveries were $2,000 in 1998 and net
charge offs were $357,000 and $88,000 in 1997 and 1996. There were no provisions
to expense in the three year period ended December 31, 1998 and the six month
period ending June 30, 1999.
For the year ended December 31, 1998, three companies purchased 23%, 26%
and 22%, respectively of the Company's natural gas and oil production. All three
customers purchased production primarily from Callon owned interests in Federal
OCS leases, CB40, MP163, MP 164/165, MB 864 and MB 952/955 fields. Because of
the nature of oil and gas operations and the marketing of production, the
Company believes that the loss of these customers would not have a significant
adverse impact on the Company's ability to sell its production.
Statements of Cash Flows
For purposes of the Consolidated Financial Statements, the Company
considers all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents.
The Company paid no federal income taxes for the three years ended December
31, 1998. During the years ended December 31, 1998, 1997 and 1996, the Company
made cash payments of $6,229,000, $4,167,000, and $251,000, respectively, for
interest charged on its indebtedness and $3,815,000 for the six months ended
June 30, 1999.
Per Share Amounts
In February 1997, the Financial Accounting Standards Board issued Statement
No. 128 ("FAS 128"), Earnings per Share, which generally simplified the manner
in which earnings per share are determined. The Company adopted FAS 128
effective December 15, 1997. In accordance with FAS 128, the Company's
previously reported earnings per share for 1996 were restated. The effect of
this accounting change on previously reported earnings per share (EPS) data was
as follows:
<TABLE>
<CAPTION>
1996
----
<S> <C>
Primary EPS as reported..................................... $.45
Effect of FAS 128........................................... .01
----
Basic EPS as restated....................................... $.46
====
Fully diluted EPS as reported............................... $.43
Effect of FAS 128........................................... .02
----
Diluted EPS as restated..................................... $.45
====
</TABLE>
Basic earnings or loss per common share were computed by dividing net
income or loss by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings per common share for the years
1997 and 1996 were determined on a weighted average basis using common shares
issued and outstanding adjusted for the effect of stock options considered
common stock equivalents computed using the treasury stock method. In 1998, all
options were excluded from the computation of diluted loss per share because
they were antidilutive. The conversion of the preferred stock was not included
in any annual calculation due to their antidilutive effect on diluted income or
loss per share.
F-9
<PAGE> 57
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the basic and diluted per share computation is as
follows (in thousands, except per share amounts):
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
----------------- --------------------------
1999 1998 1998 1997 1996
------- ------- -------- ------ ------
<S> <C> <C> <C> <C> <C> <C>
(a) Net income (loss) available for
common stock...................... $ (689) $ 556 $(33,533) $5,642 $2,663
(b) Weighted average shares
outstanding....................... 8,462 8,021 8,034 6,194 5,835
(c) Dilutive impact of stock options.... -- 212 -- 228 117
(d) Total diluted shares................ 8,462 8,233 8,034 6,422 5,952
Stock options excluded due to
antidilutive impact............... 55 -- 163 -- --
Basic earnings (loss) per share
(a/b)............................. $ (.08) $ .07 $ (4.17) $ .91 $ .46
Diluted earnings (loss) per share
(a/d)............................. $ (.08) $ .07 $ (4.17) $ .88 $ .45
</TABLE>
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable, accounts payable
and long-term debt approximates book value at December 31, 1998 and 1997 and
June 30, 1999. Fair value of long-term debt (specifically the 10% and the
10.125% senior subordinated notes) was based on quoted market value.
The calculation of the fair market value of the outstanding hedging
contracts (see Note 6) as of December 31, 1998 indicated a $1.4 million market
value benefit to the Company based on market prices at that date.
Accounts Payable and Accrued Liabilities -- Long-Term
Approximately $3,000,000 and $1,763,000 of current accounts payable and
accrued liabilities at December 31, 1998 and June 30, 1999, respectively,
related to long-term assets, primarily oil and gas properties that were financed
subsequent to year-end with long-term debt and therefore have been reclassified
as long-term.
3. INCOME TAXES
The Company follows the asset and liability method of accounting for
deferred income taxes prescribed by Financial Accounting Standards Board
Statement No. 109 ("FAS 109") "Accounting for Income Taxes". The statement
provides for the recognition of a deferred tax asset for deductible temporary
timing differences, capital and operating loss carryforwards, statutory
depletion carryforward and tax credit carryforwards, net of a "valuation
allowance". The valuation allowance is provided for that portion of the asset,
for which it is deemed more likely than not, that it will not be realized. The
F-10
<PAGE> 58
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's management determined that no valuation allowance was necessary in
1998 and 1997. Accordingly, the Company has recorded a deferred tax asset at
December 31, 1998 and 1997 as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------
1998 1997
------- -------
(IN THOUSANDS)
<S> <C> <C>
Federal net operating loss carryforward................ $ 7,916 $ 3,531
Statutory depletion carryforward....................... 4,083 4,062
Temporary differences:
Oil and gas properties............................... 3,979 (4,943)
Pipeline and other facilities........................ (2,164) (2,277)
Non-oil and gas property............................. (101) (86)
Other................................................ 2,635 961
------- -------
Total tax asset........................................ 16,348 1,248
Valuation allowance.................................... -- --
------- -------
Net tax asset.......................................... $16,348 $ 1,248
======= =======
</TABLE>
At December 31, 1998, the Company had, for federal tax reporting purposes,
net operating loss carryforwards ("NOL") of $22.6 million which expire in 2000
through 2012. Approximately $5.0 million of such carryovers are subject to
limitations on utilization as a result of ownership changes which occurred in
CPOC's common stock prior to the Consolidation and ownership changes as a result
of the Consolidation. Additionally, the Company had available for tax reporting
purposes $11.7 million in statutory depletion deductions which can be carried
forward for an indefinite period.
The provision for income taxes at the Company's effective tax rate differed
from the provision for income taxes at the statutory rate as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1998 1997 1996
-------- ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Computed expense (benefit) at the expected statutory
rate................................................. $(15,590) $4,296 $1,910
Change in valuation allowance.......................... -- -- (1,760)
Other.................................................. 490 (96) (100)
-------- ------ ------
Deferred income tax expense (benefit).................. $(15,100) $4,200 $ 50
======== ====== ======
</TABLE>
4. ACQUISITIONS
On June 26, 1997 the Company purchased an 18.8% working interest in the
Mobile Block 864 Area from Elf Exploration, Inc. The Company's net purchase
price was approximately $11.8 million. The Company further increased its
ownership in this area by purchasing Chevron U.S.A. Inc.'s interest in the
Mobile Block 864 Area for $18.8 million in November 1997.
The Company, together with an industry partner, was the high bidder on 18
offshore tracts at the Outer Continental Shelf ("OCS") Lease Sale #157 and #161,
held during 1996 in New Orleans, Louisiana, and conducted by the U.S. Department
of the Interior through its Minerals Management Service ("MMS"). The Company
holds a 25% working interest in the leases and its share of the total lease
costs was approximately $15.2 million.
F-11
<PAGE> 59
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ------------------
1999 1998 1997
-------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Credit Facility....................................... $39,100 $18,100 $ 100
10% Senior Subordinated Notes......................... 24,150 24,150 24,150
10.125% Senior Subordinated Notes..................... 36,000 36,000 36,000
------- ------- -------
99,250 78,250 60,250
Less: current portion................................. -- -- --
------- ------- -------
$99,250 $78,250 $60,250
======= ======= =======
</TABLE>
Borrowings under the Credit Facility, with Chase Manhattan Bank, are
secured by mortgages covering substantially all of the Company's producing oil
and gas properties. Currently, the Credit Facility provides for a $50 million
borrowing base ("Borrowing Base") which is adjusted periodically on the basis of
a discounted present value of future net cash flows attributable to the
Company's proved producing oil and gas reserves. Pursuant to the Credit
Facility, depending upon the percentage of the unused portion of the borrowing
base, the interest rate is equal to the lender's prime rate plus 0.125% (prime
plus 0.50% if utilized percentage of Borrowing Base is greater than 50%). The
Company, at its option, may fix the interest rate on all or a portion of the
outstanding principal balance at 1.125% above a defined "Eurodollar" rate for
periods up to six months (1.5% above if utilized percentage of borrowing base is
greater than 50%). The weighted average interest rate for the total debt
outstanding at June 30, 1999, December 31, 1998 and 1997 was 6.53%, 6.68% and
8.50%, respectively. Under the Credit Facility, a commitment fee of .25% or
.375% per annum on the unused portion of the Borrowing Base (depending upon the
percentage of the unused portion of the Borrowing Base) is payable quarterly.
The Company may borrow, pay, reborrow and repay under the Credit Facility until
October 31, 2000, on which date, the Company must repay in full all amounts then
outstanding.
On November 27, 1996, the Company issued $24,150,000 of 10% Senior
Subordinated Notes that will mature December 15, 2001. The Company used the
proceeds to reduce borrowings under the Credit Facility and for other corporate
purposes. Interest is payable quarterly beginning March 15, 1997. The notes are
redeemable at the option of the Company, in whole or in part, on or after
December 15, 1997, at 100% of the principal amount thereof, plus accrued
interest to the redemption date. The notes are general unsecured obligations of
the Company, subordinated in right of payment to all existing and future
indebtedness of the Company.
On July 31, 1997, the Company issued $36 million of its 10.125% Series A
Senior Subordinated Notes due 2002. Interest is payable quarterly beginning
September 15, 1997. The Senior Subordinated Notes were offered through a private
placement transaction. The net proceeds of the transaction were used to repay
the outstanding balance under the Credit Facility and fund a portion of the
Company's capital expenditure budget. On September 10, 1997, the Company
commenced an offer to exchange the Series A Notes for a like principal amount of
10.125% Series B Senior Subordinated Notes due 2002 (the "Series B Notes" and,
together with the Series A Notes, the "10.125% Notes"). The form and terms of
the Series B Notes are identical in all material respects to the terms of the
Series A Notes, except for certain transfer restrictions and provisions relating
to registration rights. The exchange offer was completed on November 10, 1997.
Interest on the 10.125% Notes is payable quarterly, on March 15, June 15,
September 15, and December 15 of each year. The 10.125% Notes are redeemable at
the option of the Company in whole or in part, at any time on or after September
15, 2000. The 10.125% Notes are general
F-12
<PAGE> 60
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
unsecured obligations of the Company, subordinated in right of payment to all
existing and future indebtedness of the Company and rank pari passu with the 10%
Notes.
On July 15, 1999, the Company announced its sale of $40 million of Senior
Subordinated Notes due 2004 at a yield of 10.25 percent. The net proceeds from
the offering (approximately $38.4 million), together with cash flows and
borrowings under its Credit Facility, will be used to fund the Company's
remaining 1999 capital expenditure budget and a portion of its 2000 capital
expenditure budget. Pending this use of the net proceeds, the company repaid
amounts under its credit facility, which may be reborrowed at a later date.
The Credit Facility and the subordinated debt contain various covenants
including restrictions on additional indebtedness and payment of cash dividends
as well as maintenance of certain financial ratios. The Company is in compliance
with these covenants at December 31, 1998 and June 30, 1999.
6. HEDGING CONTRACTS
The Company periodically uses derivative financial instruments to manage
oil and gas price risk. Settlements of gains and losses on commodity price swap
contracts are generally based upon the difference between the contract price or
prices specified in the derivative instrument and a NYMEX price or other cash or
futures index price, and are reported as a component of oil and gas revenues.
Gains or losses attributable to the termination of a swap contract are deferred
and recognized in revenue when the oil and gas production is sold. Approximately
$1,886,000 and $2,466,000 was recognized as additional oil and gas revenue in
1998 and 1997 and recognized a reduction in revenue of $2,757,000 in 1996 as a
result of such agreements. For the six months ended June 30, 1999 and 1998,
approximately $730,000 and $763,000 was recognized as additional oil and gas
revenue, respectively.
At June 30, 1999, the Company had open collar contracts with third parties
whereby minimum floor prices and maximum ceiling prices are contracted and
applied to related contract volumes. These agreements in effect for 1999 are for
average gas volumes of 450,000 Mcf per month through November 1999 at (on
average) a ceiling price of $2.35 and floor price of $2.02. In addition, the
Company had open oil collar contracts averaging 25,000 barrels per month at (on
average) a ceiling of $16.22 and a floor of $13.85 from July 1999 through
December 1999.
Also at June 30, 1999 the Company had open forward natural gas swap
contracts of 200,000 Mcf per month from July 1999 through September 1999 with a
fixed contract price of $2.35. In addition, the Company had open forward crude
oil swap contracts of 10,000 barrels per month with a fixed contract price of
$14.10 per month from July 1999 through September 1999.
7. COMMITMENTS AND CONTINGENCIES
As described in Note 9, abandonment trusts (the "Trusts") have been
established for future abandonment obligations of those oil and gas properties
of the Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses in
excess of the Trusts' balances. As of June 30, 1999, total estimated site
restoration, dismantlement and abandonment costs were approximately $6,100,000,
net of expected salvage value. Substantially all such costs are expected to be
funded through the Trusts' funds, all of which will be accessible to the Company
when abandonment work begins. In addition as a working interest owner and/or
operator of oil and gas properties, the Company is responsible for the cost of
abandonment of such properties. See Note 2.
The Company, as part of the Consolidation, entered into Registration Rights
Agreements whereby the former stockholders of certain of the Constituent
Entities are entitled to require the Company to register Common Stock of the
Company owned by them with the Securities and Exchange Commission for sale to
F-13
<PAGE> 61
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the public in a firm commitment public offering and generally to include shares
owned by them, at no cost, in registration statements filed by the Company.
Costs of the offering will not include discounts and commissions, which will be
paid by the respective sellers of the Common Stock.
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>
SIX MONTHS
ENDED YEARS ENDED DECEMBER 31,
JUNE 30, ------------------------------
1999 1998 1997 1996
---------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Capitalized costs incurred:
Evaluated Properties --
Beginning of period balance..................... $444,579 $398,046 $322,970 $304,737
Property acquisition costs...................... 15,923 9,464 51,751 2,999
Exploration costs............................... 14,278 42,617 13,620 8,732
Development costs............................... 9,422 4,361 14,155 8,076
Sale of mineral interest........................ -- (9,909) (4,450) (1,574)
-------- -------- -------- --------
End of period balance........................... $484,202 $444,579 $398,046 $322,970
======== ======== ======== ========
Unevaluated Properties (excluded from the full-cost
pool) --
Beginning of period balance..................... $ 42,679 $ 35,339 $ 26,235 $ 10,171
Additions....................................... 6,315 11,156 16,924 20,640
Capitalized interest and general administrative
costs......................................... 3,021 8,955 5,163 1,883
Transfer to evaluated........................... (9,506) (12,771) (12,983) (6,459)
-------- -------- -------- --------
End of period balance........................... $ 42,509 $ 42,679 $ 35,339 $ 26,235
======== ======== ======== ========
Accumulated depreciation, depletion and
amortization --
Beginning of period balance..................... 345,353 $282,891 $266,716 $257,143
Provision charged to expense.................... 7,791 18,962 16,175 9,573
Impairment of oil and gas properties............ -- 43,500 -- --
-------- -------- -------- --------
End of period balance........................... $353,144 $345,353 $282,891 $266,716
======== ======== ======== ========
</TABLE>
Unevaluated property costs, primarily lease acquisition costs incurred at
federal and state lease sales and unevaluated drilling costs being excluded from
the amortizable evaluated property base as of December 31, 1998 consisted of
$17.9 million incurred in 1998, $8.2 million incurred in 1997 and $16.6 million
incurred in 1996 and prior. These costs are directly related to the acquisition
and evaluation of unproved properties and major development projects. The
excluded costs and related reserves are included in the amortization base as the
properties are evaluated and proved reserves are established or impairment is
determined. The majority of these costs will be evaluated over the next five
year period.
Depreciation, depletion and amortization per unit-of-production (equivalent
barrel of oil) amounted to $7.16, $6.11, and $5.87 for the years ended December
31, 1998, 1997 and 1996, respectively, and $5.92 and $7.00 for the six months
ended June 30, 1999 and 1998, respectively.
F-14
<PAGE> 62
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Impairment of Oil and Gas Properties
Under full-cost accounting rules, the capitalized costs of proved oil and
gas properties are subject to a "ceiling test", which limits such costs to the
estimated present value net of related tax effects, discounted at a 10 percent
interest rate, of future net cash flows from proved reserves, based on current
economic and operating conditions (PV-10). If capitalized costs exceed this
limit, the excess is charged to expense. During the fourth quarter of 1998, the
Company recorded a noncash impairment provision related to oil and gas
properties in the amount of $43.5 million ($28.7 million after-tax) primarily
due to the significant decline in oil and gas prices.
9. NET PROFITS INTEREST
Since 1989, the Constituent Entities have entered into separate agreements
to purchase certain oil and gas properties with gross contract acquisition
prices of $170,000,000 ($150,000,000 net as of closing dates) and in
simultaneous transactions, entered into agreements to sell overriding royalty
interests ("ORRI") in the acquired properties. These ORRI are in the form of net
profits interests ("NPI") equal to a significant percentage of the excess of
gross proceeds over production costs, as defined, from the acquired oil and gas
properties. A net deficit incurred in any month can be carried forward to
subsequent months until such deficit is fully recovered. The Company has the
right to abandon the purchased oil and gas properties if it deems the properties
to be uneconomical.
The Company has, pursuant to the purchase agreements, created abandonment
trusts whereby funds are provided out of gross production proceeds from the
properties for the estimated amount of future abandonment obligations related to
the working interests owned by the Company. The Trusts are administered by
unrelated third party trustees for the benefit of the Company's working interest
in each property. The Trust agreements limit their funds to be disbursed for the
satisfaction of abandonment obligations. Any funds remaining in the Trusts after
all restoration, dismantlement and abandonment obligations have been met will be
distributed to the owners of the properties in the same ratio as contributions
to the Trusts. The Trusts' assets are excluded from the Consolidated Balance
Sheets of the Company because the Company does not control the Trusts. Estimated
future revenues and costs associated with the NPI and the Trusts are also
excluded from the oil and gas reserve disclosures at Note 12. As of December 31,
1998 and 1997 the Trusts' assets (all cash and investments) totaled $6,360,000
and $19,300,000, respectively and $6,100,000 at June 30, 1999, all of which will
be available to the Company to pay its portion, as working interest owner, of
the restoration, dismantlement and abandonment costs discussed at Note 7. The
trust asset decrease in 1998 was the result of a sale of an oil and gas property
and the related trust.
At the time of acquisition of properties by the Company, the property
owners estimated the future costs to be incurred for site restoration,
dismantlement and abandonment, net of salvage value. A portion of the amounts
necessary to pay such estimated costs was deposited in the Trusts upon
acquisition of the properties, and the remainder is deposited from time to time
out of the proceeds from production. The determination of the amount deposited
upon the acquisition of the properties and the amount to be deposited as
proceeds from production was based on numerous factors, including the estimated
reserves of the properties. The amounts deposited in the Trusts upon acquisition
of the properties were capitalized by the Company as oil and gas properties.
As operator, the Company receives all of the revenues and incurs all of the
production costs for the purchased oil and gas properties but retains only that
portion applicable to its net ownership share. As a result, the payables and
receivables associated with operating the properties included in the Company's
Consolidated Balance Sheets include both the Company's and all other outside
owner's shares. However, revenues and production costs associated with the
acquired properties reflected in the accompanying Consolidated Statements of
Operations represent only the Company's share, after reduction for the NPI.
F-15
<PAGE> 63
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. EMPLOYEE BENEFIT PLANS
The Company has adopted a series of incentive compensation plans designed
to align the interest of the executives and employees with those of its
stockholders. The following is a brief description of each plan:
The Savings and Protection Plan provides employees with the option to defer
receipt of a portion of their compensation and the Company may, at its
discretion, match a portion of the employee's deferral with cash and Company
Common Stock. The Company may also elect, at its discretion, to contribute a
non-matching amount in cash and Company Common Stock to employees. The amounts
held under the Savings and Protection Plan are invested in various funds
maintained by a third party in accordance with the directions of each employee.
An employee is fully vested immediately upon participation in the Savings and
Protection Plan. The total amounts contributed by the Company, including the
value of the common stock contributed, were $468,000, $438,000, and $241,000 in
the years 1998, 1997 and 1996, respectively.
The 1994 Stock Incentive Plan (the "1994 Plan") provides for 600,000 shares
of Common Stock to be reserved for issuance pursuant to such plan. Under the
1994 Plan the Company may grant both stock options qualifying under Section 422
of the Internal Revenue Code and options that are not qualified as incentive
stock options, as well as performance shares. No options will be granted at an
exercise price of less than fair market value of the Common Stock on the date of
grant. A total of 500,000 options were granted in 1994 and 1995 and all such
options could be exercised as of December 31, 1996. During 1997, there were no
other options granted and 9,000 shares were exercised at an average price of
$17.94. These options have an expiration date 10 years from date of grant. In
1998, 20,000 non-employee director options were granted under the plan, vesting
100% in November 1998.
On August 23, 1996, the Board of Directors of the Company approved and
adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996
Plan"). The 1996 Plan provides for the same types of awards as the 1994 Plan and
is limited to a maximum of 1,200,000 shares (as amended from the original
900,000 shares) of common stock that may be subject to outstanding awards.
During 1998, 1997 and 1996, the Company granted stock options to purchase
205,000, 20,000 and 530,000 shares, respectively, of Common Stock under the
plan. All of such options were granted at an exercise price equal to the fair
market value of the Common Stock on the date of grant. Terms of the options
granted in 1998 provide that 25% of the options become exercisable each year
beginning August of 1998 and each succeeding January. Terms of the plan for
450,000 options granted in 1996 provide that 20% of the options become
exercisable on January 1 of each succeeding year, beginning January 1, 1997.
Non-employee director options aggregating 80,000 shares vest 25% at each
succeeding annual meeting of directors following each annual stockholders'
meeting, beginning in 1997. Unvested options are subject to forfeiture upon
certain termination of employment events and expire 10 years from date of grant.
F-16
<PAGE> 64
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company accounts for the options issued pursuant to the stock incentive
plans under APB Opinion No. 25, under which no compensation cost has been
recognized. Had compensation cost for these plans been determined consistent
with FAS 123, the Company's net income and earnings per common share would have
been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
----------- --------- ---------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Net income (loss):
As reported.......................................... $(33,533) $5,642 $2,663
Pro Forma............................................ (34,421) 4,977 2,411
Basic earnings (loss) per share:
As reported.......................................... (4.17) .91 .46
Pro Forma............................................ (4.28) .80 .41
Diluted earnings (loss) per share:
As reported.......................................... (4.17) .88 .45
Pro Forma............................................ (4.28) .77 .41
</TABLE>
Because the Statement 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost above may not be representative of that to be expected in future years.
A summary of the status of the Company's two stock option plans at December
31, 1998, 1997 and 1996 and changes during the years then ended is presented in
the table and narrative below:
<TABLE>
<CAPTION>
1998 1997 1996
-------------------- -------------------- ---------------------
WTD WTD WTD
AVG AVG AVG
SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE
--------- -------- --------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding, beginning of
year........................ 1,041,000 $11.19 1,030,000 $11.10 490,000 $10.01
Granted..................... 225,000 10.08 20,000 15.31 550,000 12.06
Exercised................... -- -- (9,000) 10.00 -- --
Forfeited................... -- -- -- -- (10,000) 10.00
Expired..................... -- -- -- -- -- --
--------- ------ --------- ------ ---------- ------
Outstanding, end of year...... 1,266,000 $11.00 1,041,000 $11.19 1,030,000 $11.10
========= ====== ========= ====== ========== ======
Exercisable, end of year...... 802,250 $10.90 621,000 $10.65 500,000 $10.16
========= ====== ========= ====== ========== ======
Weighted average fair value of
options granted............. $4.31 $6.30 $4.96
</TABLE>
The options outstanding at December 31, 1998 have exercise prices ranging
from $9.47 to $16.38 with a remaining weighted average contractual life of 7.06
years.
The fair value of each option grant is estimated on the date of grant using
the Black-Scholes option pricing model with the following weighted average
assumptions used for options granted during 1998, 1997 and 1996.
<TABLE>
<CAPTION>
1998 1997 1996
---- ---- ----
<S> <C> <C> <C>
Risk free interest rate..................................... 5.1% 6.8% 6.5%
Expected life (years)....................................... 7.0 4.0 4.9
Expected volatility......................................... 28.8% 41.1% 34.7%
Expected dividends.......................................... -- -- --
</TABLE>
F-17
<PAGE> 65
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company awarded 225,000 performance shares under the 1996 Plan to the
Company's Executive officers on August 23, 1996. During June 1997, the Company's
stockholders approved the performance share awards and the related common stock
was issued. The issuance was recorded at the fair market value of the shares on
their date of grant, with a corresponding charge to stockholders' equity
representing the unearned portion of the award. All of the performance shares
granted will vest in whole on January 1, 2001, and will be subject to forfeiture
upon certain termination of employment events. The unearned portion was being
amortized as compensation expense on a straight-line basis over the vesting
period. An additional 25,000 shares were issued under the 1994 Plan in 1997 and
165,500 shares were issued to certain key employees other than the Company's
Executive officers in 1998. Approximately $4,963,000 in 1998, $714,000 in 1997
and $208,000 in 1996 of compensation cost were charged to expense related to the
restricted shares granted.
In December 1998, the Company approved the accelerated vesting of all
performance shares. As a result, an additional charge of $3,469,000 which
represents the future unamortized expense related to unvested shares at the date
the acceleration of vesting occurred, was expensed in 1998.
In addition, the Company recorded a provision of approximately $2.3 million
for retirement benefits approved in December of 1998.
11. EQUITY TRANSACTIONS
In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible
Exchangeable Preferred Stock, Series A (the "Preferred Stock"). Annual dividends
are $2.125 per share and are cumulative. The net proceeds of the $.01 par value
stock after underwriters discount and expense was $30,899,000. Each share has a
liquidation preference of $25.00, plus accrued and unpaid dividends. Dividends
on the Preferred Stock are cumulative from the date of issuance and are payable
quarterly, commencing January 15, 1996. The Preferred Stock is convertible at
any time, at the option of the holders thereof, unless previously redeemed, into
shares of Common Stock of the Company at an initial conversion price of $11 per
share of Common Stock, subject to adjustments under certain conditions.
The Preferred Stock is redeemable at any time on or after December 31,
1998, in whole or in part at the option of the Company at a redemption price of
$26.488 per share beginning at December 31, 1998 and at premiums declining to
the $25.00 liquidation preference by the year 2005 and thereafter, plus accrued
and unpaid dividends. The Preferred Stock is also exchangeable, in whole, but
not in part, at the option of the Company on or after January 15, 1998 for the
Company's 8.5% Convertible Subordinated Debentures due 2010 (the "Debentures")
at a rate of $25.00 principal amount of Debentures for each share of Preferred
Stock. The Debentures will be convertible into Common Stock of the Company on
the same terms as the Preferred Stock and will pay interest semi-annually.
On November 25, 1997, the Company completed a public offering of 1,840,000
shares of Common Stock at a price to the public of $17.00. This offering
resulted in the Company receiving cash proceeds of $29,267,000, net of offering
costs and underwriting discount. The Company used a portion of the proceeds to
repay indebtedness incurred to finance the purchase of Chevron U.S.A. Inc.'s
interest in Mobile Block 864 Area (see Note 4) and the remaining proceeds were
used to fund a portion of the 1998 capital expenditures budget.
In a December 1998 private transaction, a preferred stockholder elected to
convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's
Common Stock. During the first quarter of 1999 certain preferred stockholder's
through private transactions, agreed to convert 210,350 shares of Preferred
Stock into 502,632 shares of the Company's Common Stock. Any premium negotiated
in excess of the conversion rate was recorded as additional preferred stock
dividends.
F-18
<PAGE> 66
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 1998, 1997 and
1996 have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions.
There are numerous uncertainties inherent in establishing quantities of
proved reserves. The following reserve data represent estimates only and should
not be construed as being exact. In addition, the present values should not be
construed as the current market value of the Company's oil and gas properties or
the cost that would be incurred to obtain equivalent reserves.
Estimated Reserves
Changes in the estimated net quantities of crude oil and natural gas
reserves, all of which are located onshore and offshore in the continental
United States, are as follows:
RESERVE QUANTITIES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
--------------------------
1998 1997 1996
------- ------- ------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period.................................... 3,402 3,819 4,766
Revisions to previous estimates........................ (99) (151) (50)
Purchase of reserves in place.......................... 162 -- --
Sales of reserves in place............................. (1,531) (78) (312)
Extensions and discoveries............................. 5,274 274 --
Production............................................. (310) (462) (585)
------- ------- ------
End of period.......................................... 6,898 3,402 3,819
======= ======= ======
Natural Gas (MMcf):
Beginning of period.................................... 88,738 50,424 29,667
Revisions to previous estimates........................ (8,631) (11,174) (1,688)
Purchase of reserves in place.......................... 4,414 52,485 7,391
Sales of reserves in place............................. (684) (164) (228)
Extensions and discoveries............................. 18,229 10,281 21,551
Production............................................. (14,036) (13,114) (6,269)
------- ------- ------
End of period.......................................... 88,030 88,738 50,424
======= ======= ======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period.................................... 2,976 3,385 3,890
======= ======= ======
End of period.......................................... 1,774 2,976 3,385
======= ======= ======
Natural Gas (MMcf):
Beginning of period.................................... 88,010 49,491 20,408
======= ======= ======
End of period.......................................... 76,895 88,010 49,491
======= ======= ======
</TABLE>
F-19
<PAGE> 67
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE
The following tables present the Company's standardized measure of
discounted future net cash flows and changes therein relating to proved oil and
gas reserves and were computed using reserve valuations based on regulations
prescribed by the SEC. These regulations provide that the oil, condensate and
gas price structure utilized to project future net cash flows reflects current
prices at each date presented and have been escalated only when known and
determinable price changes are provided by contract and law. Future production,
development and net abandonment costs are based on current costs without
escalation. The resulting net future cash flows have been discounted to their
present values based on a 10% annual discount factor.
STANDARDIZED MEASURE
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows.................................. $256,325 $285,953 $285,727
Future costs --
Production......................................... (67,192) (63,709) (59,584)
Development........................................ (36,581) (12,984) (9,989)
-------- -------- --------
Future net inflows before income taxes............... 152,552 209,260 216,154
Future income taxes.................................. -- (32,781) (49,438)
-------- -------- --------
Future net cash flows................................ 152,552 176,479 166,716
10% discount factor.................................. (52,801) (48,400) (36,547)
-------- -------- --------
Standardized measure of discounted future net cash
flows.............................................. $ 99,751 $128,079 $130,169
======== ======== ========
</TABLE>
CHANGES IN STANDARDIZED MEASURE
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure -- beginning of period................. $128,079 $130,169 $ 63,764
Sales and transfers, net of production costs................ (27,807) (34,006) (18,202)
Net change in sales and transfer prices, net of production
costs..................................................... (33,029) (66,880) 32,268
Exchange and sale of in place reserves...................... (4,445) (2,428) (877)
Purchases, extensions, discoveries, and improved recovery,
net of future production and development costs............ 24,294 90,550 79,983
Revisions of quantity estimates............................. (9,409) (13,751) (3,907)
Accretions of discount...................................... 13,645 16,017 6,376
Net change in income taxes.................................. 7,926 21,633 (30,000)
Changes in production rates, timing and other............... 497 (13,225) 764
-------- -------- --------
Standardized measure -- end of period....................... $ 99,751 $128,079 $130,169
======== ======== ========
</TABLE>
F-20
<PAGE> 68
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
1998
Total revenues........................................ $11,492 $9,733 $9,339 $ 7,154
Total costs and expenses.............................. 9,664 8,606 7,919 57,383
Income taxes expense (benefit)........................ 621 380 487 (16,588)
Net income (loss)..................................... 1,207 747 933 (33,641)
Net income (loss) per share -- basic.................. .06 .01 .03 (4.27)
Net income (loss) per share -- diluted................ .06 .01 .03 (4.27)
1997
Total revenues........................................ $12,781 $8,758 $9,201 $ 12,898
Total costs and expenses.............................. 7,366 6,971 7,394 9,270
Income taxes expense.................................. 1,733 578 615 1,274
Net income............................................ 3,682 1,209 1,192 2,354
Net income (loss) per share -- basic.................. .50 .08 .08 .25
Net income (loss) per share -- diluted................ .39 .08 .08 .24
</TABLE>
F-21
<PAGE> 69
[Callon Logo] CALLON PETROLEUM COMPANY
200 NORTH CANAL ST.
NATCHEZ, MS 39120
(601) 442-1601
$125,000,000
DEBT SECURITIES
PREFERRED STOCK
COMMON STOCK
SECURITIES WARRANTS
SECURITIES PURCHASE CONTRACTS
Callon Petroleum Company's common stock is listed on the New York Stock
Exchange, under the symbol "CPE."
We will provide specific terms of these securities in supplements to this
prospectus. You should read this prospectus and any supplement carefully before
you invest.
---------------------
This prospectus may not be used to consummate sales of securities unless we
also furnish you with a prospectus supplement describing the final terms of the
securities offered.
---------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
THIS PROSPECTUS IS DATED OCTOBER 6, 1999
<PAGE> 70
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
About This Prospectus....................................... 1
Where You Can Find More Information......................... 1
Disclosure Regarding Forward Looking Statements............. 2
About Callon Petroleum Company.............................. 2
Use of Proceeds............................................. 2
Ratios of Earnings to Fixed Charges and of Earnings to
Combined Fixed Charges and Preferred Stock Dividends...... 3
Description of Debt Securities.............................. 3
Description of Capital Stock................................ 14
Description of Securities Warrants.......................... 17
Description of Securities Purchase Contracts and Securities
Purchase Units and Prepaid Securities..................... 18
Plan of Distribution........................................ 19
Experts..................................................... 20
Legal Matters............................................... 20
</TABLE>
i
<PAGE> 71
ABOUT THIS PROSPECTUS
In this prospectus, the words "Company," "we," "our," "ours" and "us" refer
to Callon Petroleum Company, and its subsidiaries, unless otherwise stated or
the context requires.
This prospectus is part of a registration statement that we have filed with
the SEC utilizing a shelf registration process. Under this shelf process, we may
sell the securities described in this prospectus in one or more offerings up to
a total dollar amount of $125,000,000. This prospectus provides you with a
general description of the securities we may offer. Each time we sell
securities, we will provide a prospectus supplement containing specific
information about the terms of that offering. The prospectus supplement may also
add, update or change the information in this prospectus. You should read this
prospectus, the relevant prospectus supplement and the information described
under the heading "Where You Can Find More Information."
We believe that we have included or incorporated by reference all
information material to investors in this prospectus, but certain details that
may be important for specific investment purposes have not been included. To see
more detail, you should read the exhibits filed with or incorporated by
reference into this registration statement.
WHERE YOU CAN FIND MORE INFORMATION
We file annual, quarterly and special reports, proxy statements and other
information with the SEC. You may read and copy any document we file, including
the registration statement, at the SEC's public reference room located at 450
Fifth Street, N.W., Washington, D.C., 20549, or its public reference rooms
located in New York, New York and Chicago, Illinois. Please call the SEC at
1-800-SEC-0330 for information on the operation of the public reference rooms.
Our SEC filings are also available to the public from the SEC's web site at
http://www.sec.gov. They are located in the EDGAR database on that web site. You
may also obtain information about us from the New York Stock Exchange, where our
common stock is listed.
The SEC allows us to incorporate by reference information from the
documents we file with them, which means that we can disclose important
information to you by referring you to those documents. The information
incorporated by reference is considered to be part of this prospectus, and
information that we later file with the SEC will automatically update and
supersede this information. Specifically, we incorporate by reference the
documents listed below and any future filings we make with the SEC (including
any filings we make prior to the effectiveness of the registration statement)
under Sections 13(a), 13(c), 14, or 15(d) of the Securities Exchange Act of 1934
until the offering is terminated:
- Our Annual Report on Form 10-K for the year ended December 31, 1998;
- Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 1999
and June 30, 1999;
- Our Current Reports on Form 8-K filed on February 3, 1999 and March 3,
1999;
- The description of our common stock contained in the Registration
Statement on Form 8-B filed on October 3, 1994; and
- The description of our convertible exchangeable preferred stock contained
in the Registration Statement on Form 8-A filed on November 13, 1995, as
amended and Form 8-A/A filed on November 21, 1995.
This prospectus is part of a registration statement we filed with the SEC
(Registration No. 333-87945).
You may request a copy of any of the information incorporated by reference,
at no cost, by writing or telephoning us at the following address:
Callon Petroleum Company
200 North Canal Street
Natchez, MS 39120
(601) 442-1601
Attention: Corporate Secretary
You should rely only on the information incorporated by reference or
provided in this prospectus or any prospectus supplement. We have not authorized
anyone else to provide you
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<PAGE> 72
with different information. We are not making an offer of these securities in
any state where the offer is not permitted. You should not assume that the
information in this prospectus or any prospectus supplement is accurate as of
any date other than the date on the front of those documents.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus includes forward-looking statements. We can not assure you
that the plans, intentions or expectations upon which our forward-looking
statements are based will occur. Our forward-looking statements are subject to
risks, uncertainties and assumptions, including those discussed elsewhere in
this prospectus and the documents that are incorporated by reference into this
prospectus. Some of these risks which could affect our future results and could
cause results to differ materially from those expressed in our forward-looking
statements include:
- the volatility of oil and natural gas prices;
- the uncertainty of estimates of oil and natural gas reserves;
- the impact of competition;
- difficulties encountered during the exploration for and production of oil
and natural gas;
- the difficulties encountered in delivering oil and natural gas to
commercial markets;
- changes in customer demand;
- the uncertainty of our ability to attract capital;
- changes in the extensive government regulations regarding the oil and
natural gas business; and
- compliance with environmental regulations.
The information contained in this prospectus and in the documents
incorporated by reference into this prospectus identify additional factors that
could affect our operating results and performance. We urge you to carefully
consider those factors.
Our forward-looking statements are expressly qualified in their entirety by
this cautionary statement.
ABOUT CALLON PETROLEUM COMPANY
We have been engaged in the exploration, development, acquisition and
production of oil and gas properties since 1950. Our properties are
geographically concentrated offshore in the Gulf of Mexico, where we have
substantial experience. Since 1996, our primary focus has been on acquiring
exploration prospects, conducting 3-D and conventional 2-D seismic surveys of
these prospects and drilling exploration wells. We have assembled a balanced
portfolio of exploration projects in the Gulf of Mexico composed of:
- controlling working interests in projects with low exploration risk and
low drilling and completion costs targeting reserve deposits of between
three and 10 Bcf in the shallow Miocene area at depths of less than 4,000
feet;
- significant working interest in projects with higher exploration risk and
higher drilling and completion costs targeting reserve deposits of
between 10 and 100 Bcfe in the outer continental shelf area at depths of
between 7,000 and 17,000 feet; and
- small working interest in projects with high exploration risk and high
drilling and completion cost targeting reserve deposits in the deep water
area of the Gulf of Mexico.
Our principal executive offices are located at 200 North Canal Street,
Natchez, Mississippi 39120 and our telephone number is (601) 442-1601.
USE OF PROCEEDS
Unless otherwise set forth in the applicable prospectus supplement,
proceeds from the sale of the securities sold by us will be used for general
corporate purposes. These purposes may include
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<PAGE> 73
acquisitions, working capital, capital expenditures, the repurchase of
outstanding securities and the repayment of indebtedness. Proceeds from the sale
of securities initially may be temporarily invested in short-term securities.
RATIOS OF EARNINGS TO FIXED CHARGES AND OF EARNINGS
TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
Our ratios of earnings to fixed charges and of earnings to combined fixed
charges and preferred stock dividends for the periods indicated below as
calculated under generally accepted accounting principles are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED
-------------------------------- JUNE 30,
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- -----------------
<S> <C> <C> <C> <C> <C> <C>
Ratio of earnings to fixed charges........... -- 1.6 8.8 3.3 -- --
Ratio of earnings to combined fixed charges
and preferred stock dividends.............. -- 1.3 1.2 1.7 -- --
</TABLE>
When we calculate our ratio of earnings to fixed charges, "earnings" are
composed of the following:
- consolidated earnings or loss from continuing operations before tax,
excluding undistributed equity earnings or affiliated companies; plus
- fixed charges, excluding capitalized interest.
Fixed charges are comprised of the following:
- interest expense on indebtedness and capitalized interest;
- amortization of debt issuance costs, discounts and premiums; and
- the portion of capitalized leases deemed to be representative of
interest.
Earnings did not cover fixed charges by $679,000 through the second quarter
of 1999, $50.3 million in 1998 and $313,000 in 1994.
In calculating the ratio of earnings to combined fixed charges and
preferred stock dividends, fixed charges include pre-tax preferred stock
dividend requirements.
Earnings did not cover combined fixed charges and preferred stock dividends
by $2.7 million through the second quarter of 1999, $54.5 million in 1998 and
$313,000 in 1994.
DESCRIPTION OF DEBT SECURITIES
The debt securities will be our direct unsecured obligations. The debt
securities will be either senior debt securities or subordinated debt
securities. The debt securities will be issued under one or more indentures
between us and a trustee that we will name in the prospectus supplement. Senior
debt securities will be issued under a "senior indenture" and subordinated debt
securities will be issued under a "subordinated indenture." Together, we refer
to the senior indenture and subordinated indenture as the "indentures."
We have not restated the indentures in their entirety. We filed the forms
of the indentures as exhibits to our registration statement. You should read the
indentures because they, and not this description, will control your rights as
holders of debt securities. In the summary below, we have included references to
section numbers of the applicable indentures so that you can easily locate these
provisions. Capitalized terms used in the summary have the meanings specified in
the indentures.
Unless otherwise specifically noted in the following discussion, references
to "we," "us" or "our" means Callon Petroleum Company without its subsidiaries.
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<PAGE> 74
We have summarized the material provisions of the indentures in the
following order:
- those applicable to both indentures; and
- those applicable only to the subordinated indenture.
PROVISIONS APPLICABLE TO BOTH SENIOR AND SUBORDINATED DEBT SECURITIES
General
The debt securities described in a prospectus supplement will be our
unsecured, senior or subordinated obligations. The senior debt securities will
rank equally with all of our other unsecured and unsubordinated debt, and will
rank senior to our subordinated debt. The subordinated debt securities will have
a junior position to our senior indebtedness. Subordinated debt securities may
rank equally with or junior to our existing subordinated indebtedness. The terms
of subordination are described below under "Provisions Applicable Solely to
Subordinated Debt Securities -- Subordination" and may be further described or
changed in a prospectus supplement.
A prospectus supplement relating to any series of debt securities that we
offer will include specific terms relating to that series. These terms will
include, among other things, some or all of the following:
- the title of the debt securities;
- the total principal amount;
- whether they are senior debt securities or subordinated debt securities;
- if they are subordinated debt securities, the terms of subordination if
different from those described below;
- whether the series of debt securities are issuable as registered
securities, bearer securities or both;
- whether any debt securities of the series are to be issuable in temporary
or permanent global form with or without coupons, and whether permanent
global securities may be exchanged for securities of such series;
- the person to whom any interest on any series shall be payable;
- the dates on which principal and any premium on the debt securities will
be payable;
- the interest rate or the method used to determine the interest rate,
record and interest payment dates;
- whether and under what circumstances any additional amounts with respect
to the debt securities will be payable;
- the place or places where payments on the debt securities are payable or
the method of payment and where the debt securities may be surrendered
for transfer or exchange;
- any optional redemption provisions;
- any sinking fund or other provisions that would obligate us to repurchase
or otherwise redeem the series of debt before final maturity;
- the denominations in which the debt securities will be issuable;
- whether payments on the debt securities will be payable in foreign
currency or currency units or another form, and whether payments will be
payable by reference to any index or formula;
- the portion of the principal amount of debt securities that will be
payable if the maturity is accelerated, if other than the entire
principal amount;
- whether the securities of the series will be issued in the form of
book-entry securities, the depositary for such series, and the
circumstances for exchanging such book-entry securities for certificated
securities;
- any means of defeasance on the debt securities and any additional
conditions or limitations to defeasance of the debt securities;
- any changes to or additional events of default or covenants;
- if the principal amount payable at the stated maturity of any securities
will not be determinable at any time prior to the stated maturity, the
amount which shall be deemed to be the principal amount of such
securities as of any such time;
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<PAGE> 75
- any restriction or condition on the transfer or exchange of the debt
securities;
- any rights that we may have to defer payments of interest;
- any terms for the conversion or exchange of the debt securities for other
securities of ours or any other entity; and
- any other terms of the series of debt securities.
A series of debt securities may be issued with an original issue discount.
An original issue discount provides that less than the entire principal amount
of the series of debt securities is payable upon declaration of acceleration of
the maturity of the series of debt securities. Special U.S. federal income tax
considerations may be applicable to debt securities issued at an original issue
discount. These special considerations will be set forth in a prospectus
supplement relating to the series of debt securities.
The indentures do not limit the amount of debt securities or other types of
indebtedness we may issue. The indentures allow debt securities to be issued up
to any principal amount that we may authorize. The subordinated indenture allows
us to issue subordinated debt securities which are convertible into other
securities, including shares of our common stock or preferred stock.
Debt securities may be issued in certificated or global form. (Sections
201, 203 and 301)
Information about the Trustee
The trustee may resign at any time. The prospectus supplement will describe
any rights the holders of a series of debt securities have to remove the
trustee. Under the Trust Indenture Act of 1939, as amended, governing trustee
conflicts of interest, any uncured Event of Default with respect to any series
of senior debt securities will force the trustee to resign as trustee under
either the subordinated indenture or the senior indenture. Similarly, any
uncured Event of Default with respect to any series of subordinated debt
securities will force the trustee to resign as trustee under either the senior
indenture or subordinated indenture. If the trustee resigns, is removed or
becomes incapable of acting as trustee, a successor trustee will have to be
appointed in accordance with the provisions of the applicable indenture.
Denominations
The prospectus supplement for each series of debt securities will state
whether we will issue the debt securities in registered form or in bearer form.
Modification of Indentures; Waiver of Covenants
We generally may amend the indentures or the debt securities with the
written consent of a majority in principal amount of the outstanding debt
securities of each series affected by the amendment, with each series voting
separately as a class. The holders of a majority in principal amount of the
outstanding debt securities of any series may also waive our compliance with any
provision of the indentures with respect to debt securities of that series. We
must, however, obtain the consent of each holder of debt securities affected by
an amendment or waiver which does, among other things, any of the following:
- changes the stated maturity of, or any installment of principal of or
interest on, any debt securities;
- reduces the principal amount of, or rate of interest or premium payable
on, any debt securities;
- reduces the amount of the principal of an original issue discount
security or other security which would be payable upon acceleration of
the debt securities;
- adversely affects any right of repayment at the option of a holder of any
debt security;
- reduces the amount of, or postpones the date fixed for, the payment of
any sinking fund or analogous obligation;
- changes the place of payment where, or the currency in which, any debt
security is payable;
- impairs the right to institute suit for the enforcement of any payment on
or after the stated maturity date of any debt security; or
- reduces the percentage of holders required to consent to any supplements,
modifications, waivers or amendments to the indentures. (Section 902)
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<PAGE> 76
Additionally, the subordinated indenture may not be modified to alter the
terms of subordination of any outstanding series of subordinated debt securities
without the consent of the holder of senior indebtedness that would be adversely
affected by the modification. (Section 907 of the subordinated indenture)
If we issue convertible subordinated debt securities, the terms of
conversion may not be modified in a manner which is adverse to the holders of
the convertible subordinated debt securities without the consent of such
holders. (Section 902 of the subordinated indenture)
If we issue a series of debt securities with an original issue discount or
with a principal amount that is not fixed, the applicable prospectus supplement
will describe the manner in which we will determine whether holders of a
majority of principal amount of a series of debt securities have approved a
modification or waiver of a provision of an indenture.
We may amend the indentures or outstanding debt securities without notice
to or consent from any holder of the debt security to do, among other things,
any of the following:
- permit a successor corporation to assume our obligations under the
indenture following a merger, consolidation or similar transaction;
- add to our covenants for the benefit of the holders of any series of debt
securities;
- add additional events of default for the benefit of the holders of all or
any series of securities;
- accept the appointment of a successor trustee of one or more series and
to provide for more than one trustee, if applicable;
- cure any ambiguity, defect or inconsistency;
- secure debt securities issued pursuant to the indentures;
- provide that bearer securities may be registrable as to principal, amend
restrictions on the payment of principal, premiums or interest on bearer
securities, or permit bearer securities to be issued in exchange for
registered securities or bearer securities of other authorized
denominations;
- amend any provision of an indenture in a manner that does not apply to,
or modify the rights of holders of, any debt securities outstanding at
the time and entitled to rely on the provision;
- provide for uncertificated securities of any series;
- comply with the requirements of the SEC in order to effect or maintain
the qualification of the indentures under the Trust Indenture act; or
- make any change that does not adversely affect the interests of any
holder of outstanding debt securities. (Section 901)
Meetings of Holders of Debt Securities
Each indenture contains provisions for convening meetings of the holders of
a series if debt securities of that series are issuable as bearer securities.
(Section 1401) A meeting may be called at any time by the Trustee, by our board
of directors or the holders of at least 10% in aggregate principal amount of the
outstanding securities of such series. (Section 1402) Except for any consent
which must be given by the holder of each outstanding security affected thereby,
as described above, any resolution presented at a meeting (or adjourned meeting
at which a quorum is present) may be adopted by the affirmative vote of the
holders of a majority in aggregate principal amount of the outstanding
securities of that series; provided, however, that any resolution with respect
to any request, demand, authorization, direction, notice, consent, waiver or
other action which may be made, given or taken by the holders of a specified
percentage which is less than a majority in aggregate principal amount of the
outstanding securities of a series may be adopted at a meeting (or adjourned
meeting duly reconvened at which a quorum is present) by the affirmative vote of
the holders of such specified percentage in aggregate principal amount of the
outstanding securities of that series. Any resolution passed or decision taken
at any meeting of holders of any series duly held in accordance with the
applicable indenture will be binding on all holders of that series and related
coupons. The quorum at any meeting, and at any reconvened meeting, will be
persons holding or representing a majority in aggregate principal amount of the
outstanding securities of a series. (Section 1404)
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<PAGE> 77
No Protection if a Change of Control Occurs
Unless we otherwise state in a prospectus supplement, the debt securities
will not contain any provision which may allow holders of debt securities the
right to require us to repurchase the debt securities if a change of control
occurs or if we engage in a transaction which materially increases our leverage.
A change of control or a highly leveraged transaction could adversely affect the
holders of debt securities.
Events of Default
Unless we inform you otherwise in the prospectus supplement, "Event of
Default" means any of the following (Section 501):
- failure to pay the principal of or any premium on any debt security when
due;
- failure to pay interest on any debt security within 30 days after due;
- failure to deposit any sinking fund payment within 30 days after due;
- failure to perform, or breach of, any other covenant in the indenture
(other than an agreement or covenant that we have included in the
indenture solely for the benefit of other series of debt securities) that
continues for 90 days after we are given written notice;
- our bankruptcy, insolvency or reorganization; or
- any other Event of Default for that series of debt securities described
in the applicable prospectus supplement.
An Event of Default for a particular series of debt securities may, but
does not necessarily, constitute an Event of Default for any other series of
debt securities.
If an Event of Default for any series of debt securities occurs and
continues, the trustee or the holders of at least 25% in aggregate principal
amount of the debt securities of the series may declare the entire principal of
all the debt securities of that series to be due and payable immediately. If
this happens, subject to certain exceptions, the holders of a majority of the
aggregate principal amount of the debt securities of that series can void the
declaration. (Section 502).
The indentures provide that a holder of a series of debt securities may not
file a lawsuit or otherwise institute proceedings under the indenture or appoint
a receiver or trustee unless the following happens:
- the holders give the trustee written notice;
- the holders of 25% of the series of debt securities also give such notice
and offer reasonable indemnification to the trustee;
- the holders of at least a majority of the aggregate principal amount of
the series of debt securities do not give an inconsistent notice; and
- the trustee does not institute the proceeding within 60 days of the
demand. (Section 507).
The four requirements listed above do not apply to proceedings instituted
by a holder of a series of debt securities to enforce the payment of principal,
premium or interest. (Section 508).
If we issue a series of debt securities with an original issue discount,
the prospectus supplement will describe the amount a holder of the debt
securities is entitled to receive if the series of debt securities is declared
due and payable.
The trustee is not obligated to exercise any of its rights or powers under
an indenture at the request or direction of any holders, unless the holders
offer the trustee reasonable indemnity against costs, expenses and liabilities.
(Section 602). If they provide this reasonable indemnification, the holders of a
majority in aggregate principal amount of the outstanding debt securities of any
series may direct the time, method and place of conducting any proceeding or any
remedy available to the trustee, or exercising any power conferred upon the
trustee, for any series of debt securities. The trustee is not required to take
action which the trustee determines is prejudicial to the holders of the series
of debt securities who do not request the trustee to take the action, or which
may cause the trustee to have personal liability. (Sections 512 and 601).
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Covenants
Under the indentures, we have agreed, among other things, to:
- pay the principal of and any interest and any premium on the debt
securities when due (Section 1001);
- maintain a place of payment (Section 1002);
- deposit sufficient funds with the paying agent on or before the due date
for any principal, interest or any premium payment or, if we act as our
own paying agent, segregate such funds and hold them in trust for the
benefit of the holders of the debt securities (Section 1003);
- make all payments on the debt securities to holders who are United States
aliens without withholding for any taxes or other governmental charges,
if the debt securities of a series so provides; provided that if we are
required to make any such withholding, we will pay the additional amount
of such withholding to such holders (Section 1004); and
- deliver a report to the trustee at the end of each fiscal year reviewing
our obligations under the indenture (Section 1006).
Consolidation, Merger or Sale
The indentures generally permit us to consolidate or merge with or sell,
transfer or lease all or substantially all of our assets to another entity if we
comply with the terms and conditions of the indentures relating to such a
transaction, which include the following:
- the remaining or acquiring entity (if other than us) must (i) be formed
in a U.S. jurisdiction and (ii) assume all of our responsibilities and
liabilities under the indentures including the payment of all amounts
payable on the debt securities and performance of all the covenants in
the indentures;
- the transaction must not cause a default or event of default to occur;
and
- we must deliver to the trustee a certificate signed by certain of our
officers and an opinion of counsel stating that the transaction complies
with the indentures.
The remaining or acquiring entity will be substituted for us in the
indentures with the same effect as if it had been an original party to the
indentures. Thereafter, our successor may exercise our rights and powers under
the indentures, in our name or in its own name. Any act or proceeding required
or permitted to be done by our board of directors or any of our officers may be
done by the board or officers of the successor entity. If we sell all or
substantially all of our assets, we will be released from all our liabilities
and obligations under the indentures and under the debt securities. (Sections
801 and 803).
Defeasance
When we use the term defeasance, we mean discharge from some or all of our
obligations under an indenture. The following discussion of legal defeasance and
covenant defeasance (Sections 1301 to 1306) will be applicable to a series of
debt securities (other than convertible subordinated debt securities) only if we
choose to have them apply to that series.
Legal Defeasance
If we provide in an applicable prospectus supplement, and as long as we
take steps to make sure that you receive all or your payments under the debt
securities of that series and are able to transfer the debt securities of that
series, we can elect to legally release ourselves from any obligations on such
series of debt securities (such a release is called "legal defeasance") other
than:
- the rights of holders of outstanding notes to receive payments in respect
of the principal of and premium and interest on the debt securities when
these payments are due;
- our obligation to replace any temporary debt securities, register the
transfer or exchange of any debt securities, replace mutilated, lost or
stolen debt securities, compensate and reimburse the trustee, remove and
appoint a successor trustee, maintain an office or agency for payments in
respect of the debt securities and qualify the indenture under the Trust
Indenture Act;
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- the rights, powers, trusts, duties and immunities of the trustee; and
- the legal defeasance provisions of the indentures. (Section 1304)
In order for us to accomplish legal defeasance, the following must occur:
- We must irrevocably deposit with the trustee cash and/or U.S. government
and/or U.S. government agency securities that will generate enough cash
to make interest, principal and any other payments on such debt
securities on their various due dates.
- Such defeasance shall not cause the trustee to have a conflict of
interest.
- There must be a change in current U.S. federal tax law or an IRS ruling
that lets us make that deposit without causing you to be taxed on the
debt securities any differently than if we did not make the deposit and
just repaid the debt securities ourselves. Under current U.S. federal tax
law, the deposit and our legal release from the securities would be
treated as though we took back your debt securities and gave you your
share of the cash and notes or bonds deposited in trust. In that event,
you could recognize gain or loss on the debt securities you give back to
us.
- We must deliver to the trustee a legal opinion of our counsel confirming
the tax law change described above and that all of the conditions to
legal defeasance in the indenture have been satisfied.
We will not be able to achieve legal defeasance if there is a continuing
default or event of default under the indentures or if doing so would violate
any other material agreement to which we are a party. (Section 1304). If we ever
were to accomplish legal defeasance as described above, you would have to rely
solely on the trust deposit for repayment of the debt securities. You could not
look to us for repayment in the unlikely event of any shortfall.
Covenant Defeasance
Under current U.S. federal tax law, we can make the same type of deposit
described above and be released from certain covenants relating to a series of
debt securities. The release from these covenants is called covenant defeasance.
In that event, you would lose the protection of these covenants but would gain
the protection of having money and/or securities set aside in trust to repay the
series of debt securities. We may not defease an obligation, if any, to convert
a series of debt securities into shares of our common stock, preferred stock or
other securities as provided in the subordinated indenture. In order to achieve
covenant defeasance, we must do the following:
- We must deposit in trust for the benefit of all holders of the series of
debt securities cash and/or U.S. government or U.S. government agency
securities that will generate enough cash to make interest, principal and
any other payments on the debt securities on their various due dates.
- We must deliver to the trustee a legal opinion of our counsel confirming
that under current U.S. federal tax law we may make that deposit without
causing you to be taxed on the debt securities any differently than if we
did not make the deposit and just repaid the debt securities ourselves.
The opinion also must state that all of the conditions to covenant
defeasance in the indenture have been fulfilled.
Further, such defeasance may not cause the trustee to have a conflict of
interest.
We will not be able to achieve covenant defeasance if there is a continuing
default or event of default under the indenture or if doing so would violate any
other material agreements to which we are a party. The indenture describes the
types of covenants we may fail to comply with without causing an event of
default if we accomplish covenant defeasance. (Section 1303).
If we elect to make a deposit resulting in covenant defeasance, the amount
of money and/or U.S. government or U.S. government agency securities deposited
in trust should be sufficient to pay amounts due on the debt securities at the
time of their maturity. However, if the maturity of the debt securities is
accelerated due to the occurrence of an event of default, the amount in trust
may not be sufficient to pay all amounts due on the debt securities. We would
remain liable for
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the shortfall as described in the applicable indenture.
Form, Exchange, Registration and Transfer
We may issue debt securities of a series in definitive form solely as
registered securities, solely as bearer securities or as both registered
securities and bearer securities. Unless we otherwise indicate in an applicable
prospectus supplement, bearer securities will have interest coupons attached.
(Section 201) The indentures also provide that debt securities of a series may
be issuable in temporary or permanent global form. (Section 201)
Registered securities of any series will be exchangeable for other
registered securities of the same series of any authorized denominations and of
a like aggregate principal amount and tenor. In addition, if debt securities of
any series are issuable as both registered securities and bearer securities, at
the option of the holder, and subject to the terms of the applicable indenture,
bearer securities (with all unmatured coupons, except as provided below, and all
matured coupons in default) of such series will be exchangeable for registered
securities of the same series of any authorized denominations and of a like
aggregate principal amount and tenor. Bearer securities surrendered in exchange
for registered securities between a regular record date or a special record date
and the relevant date for payment of interest shall be surrendered without the
coupon relating to such date for payment of interest, and interest accrued as of
such date will not be payable in respect of the registered security issued in
exchange for such bearer security, but will be payable only to the holder of
such coupon when due in accordance with the terms of the applicable indenture.
Unless we otherwise provide with respect to any series of debt securities,
bearer securities will not be issued in exchange for registered securities.
(Section 305)
Debt securities may be presented for exchange as provided above, and
registered securities may be presented for registration of transfer (with the
form of transfer endorsed thereon duly executed), at the office of the security
registrar or at the office of any transfer agent designated by us for such
purpose with respect to any series of debt securities and referred to in an
applicable prospectus supplement, without service charge and upon payment of any
taxes and other governmental charges as described in the indentures. Such
transfer or exchange will be effected upon the security registrar or such
transfer agent, as the case may be, being satisfied with the documents of title
and identity of the person making the request. The Trustee will serve initially
as security registrar for purposes of registering registered securities and
transfers of registered securities. (Section 305) If a prospectus supplement
refers to any transfer agents (in addition to the security registrar) initially
designated by us with respect to any series of debt securities, we may at any
time rescind the designation of any such transfer agent or approve a change in
the location through which any such transfer agent acts, except that, if debt
securities of a series are issuable solely as registered securities, we will be
required to maintain a transfer agent in each place of payment for such series
and, if debt securities of a series are also issuable as bearer securities, we
will be required to maintain (in addition to the security registrar) a transfer
agent in a place of payment for such series located outside the United States.
We may at any time designate additional transfer agents with respect to any
series of debt securities. (Section 1002)
In the event of any redemption in part, we shall not be required to
- issue, register the transfer of or exchange debt securities of any series
during a period beginning at the opening of business 15 days prior to the
selection of debt securities of that series for redemption and ending on
the close of business on (A) if debt securities of the series are
issuable only as registered securities, the day of mailing of the
relevant notice of redemption and (B) if debt securities of the series
are issuable as bearer securities, the date of the first publication of
the relevant notice of redemption, or if debt securities of the series
are also issuable as Registered Securities and there is no publication,
the mailing of the relevant notice of redemption, or
- register the transfer of or exchange any registered security, or portion
thereof, called for redemption, except the unredeemed portion of any
registered security being redeemed in part, or
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- exchange any bearer security called for redemption, except that such a
bearer security may be exchanged for a registered security of that series
and like tenor, provided that such registered security shall be
simultaneously surrendered for redemption. (Section 305)
Payment and Paying Agents
Unless we otherwise indicate in an applicable Prospectus Supplement,
payment of principal of and any premium and interest on bearer securities will
be payable, subject to any applicable laws and regulations, at the offices of
such paying agents outside the United States as we may designate from time to
time, in the manner indicated in such prospectus supplement. (Section 1002)
Unless we otherwise indicate in an applicable prospectus supplement, payment of
interest on bearer securities on any interest payment date will be made only
against surrender to the paying agent of the coupon relating to such interest
payment date. (Section 1001) No payment with respect to any bearer security will
be made at any of our offices or agencies in the United States or by check
mailed to any address in the United States or by transfer to any account
maintained with a bank located in the United States. Notwithstanding the
foregoing, payments of principal of and any premium and interest on bearer
securities denominated and payable in U.S. dollars will be made at the office of
our paying agent in New York City, if (but only if) payment of the full amount
thereof in U.S. dollars at all offices or agencies outside the United States is
illegal or effectively precluded by exchange controls or other similar
restrictions. (Section 1002)
Unless we otherwise indicate in an applicable prospectus supplement,
payment of principal of and any premium and interest on registered securities
will be made at the office of such paying agent or paying agents as we may
designate from time to time, except that at our option payment of any interest
may be made by check mailed on or before the due date to the holder's registered
address or by wire transfer. (Section 307) Unless we otherwise indicate in an
applicable prospectus supplement, payment of any installment of interest on
registered securities will be made to the person in whose name such registered
security is registered at the close of business on the regular record date for
such interest. (Section 307)
Unless we otherwise indicate in an applicable prospectus supplement, the
trustee will act as its own paying agent for payments with respect to debt
securities which are issuable solely as registered securities, and we will
maintain a paying agent outside the United States for payments with respect to
debt securities (subject to limitations described above in the case of bearer
securities) which are issuable solely as bearer securities or as both registered
securities and bearer securities. We will name any paying agents outside the
United States and any other paying agents in the United States initially
designated by us for the debt securities in an applicable prospectus supplement.
We may at any time designate additional paying agents or rescind the designation
of any paying agent or approve a change in the office through which any paying
agent acts, except that, if debt securities of a series are issuable solely as
registered securities, we will be required to maintain a paying agent in each
place of payment for such series and, if debt securities of a series are
issuable as bearer securities, we will be required to maintain (i) a paying
agent in New York City for principal payments with respect to any registered
securities of the series (and for payments with respect to bearer securities of
the series in the circumstances described above, but not otherwise), and (ii) a
paying agent in a place of payment located outside the United States where debt
securities of such series and any coupons appertaining thereto may be presented
and surrendered for payment. (Section 1002)
All moneys paid by us to a paying agent for the payment of principal of and
any premium or interest on any debt security which remain unclaimed at the end
of one year after such principal, premium or interest shall have become due and
payable will (subject to applicable escheat laws) be repaid to us, and the
holder of such debt security or any coupon will thereafter look only to us for
payment thereof. (Section 1003)
Global Debt Securities
Debt securities of a series may be issued in whole or in part in the form
of one or more global debt securities that will be deposited with, or on behalf
of, a depository identified in the prospectus supplement relating to such
series. (Section 203) Unless and until it is exchanged in whole or in part for
the individual debt securities represented
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thereby, a global debt security may not be transferred except as a whole by the
depository for such global debt security to a nominee of such depository or by a
nominee of such depository to such depository or another nominee of such
depository or by the depository or any nominee to a successor depository or any
nominee of such successor. (Section 305)
We will describe the specific terms of the depository arrangement with
respect to a series of debt securities and certain limitations and restrictions
relating to a series of bearer securities in the form of one or more global debt
securities will be described in the prospectus supplement relating to such
series.
Governing Law
New York law will govern the indenture and the debt securities.
Notices
Except as otherwise provided in the indentures, notices to holders of
bearer securities will be given by publication at least twice in a daily
newspaper in New York City and in such other city or cities as may be specified
in such bearer securities. Notices to holders of registered securities will be
given by mail to the addresses of such holders as they appear in the security
register. (Section 106)
Title
Title to any bearer securities (including bearer securities in permanent
global form) and any coupons appertaining thereto will pass by delivery. We, the
Trustee and any agent of ours or the Trustee may treat the bearer of any bearer
security and the bearer of any coupon and the registered owner of any registered
security as the owner thereof (whether or not such debt security or coupon shall
be overdue and notwithstanding any notice to the contrary) for the purpose of
making payment and for all other purposes. (Section 308)
Replacement of Securities and Coupons
We will replace any mutilated debt security or a debt security with a
mutilated coupon appertaining thereto at the expense of the holder upon
surrender of such debt security to the trustee. We will replace debt securities
or coupons that became destroyed, stolen or lost at the expense of the holder
upon delivery to the trustee of the debt security and coupons or evidence of
destruction, loss or theft thereof satisfactory to us and the trustee; in the
case of any coupon which becomes destroyed, stolen or lost, we will replace such
coupon by issuance of a new debt security in exchange for the debt security to
which such coupon appertains. In the case of a destroyed, lost or stolen debt
security or coupon, an indemnity satisfactory to the trustee and us may be
required of the holder of such debt security or coupon before we will issue a
replacement debt security. (Section 306)
PROVISIONS APPLICABLE SOLELY TO SUBORDINATED DEBT SECURITIES
Subordination
Under the subordinated indenture, payment of the principal, interest and
any premium on the subordinated debt securities will be subordinated and junior
in right of payment to the prior payment in full of certain of our senior
indebtedness. (Section 1701) The indebtedness that will be senior indebtedness
with respect to a series of subordinated debt securities is described in the
subordinated indenture as may be modified by the applicable supplemental
indenture.
The subordinated indenture provides that no payment of principal, interest
or premium may be made on the subordinated debt securities if:
- we fail to pay the principal, interest, any premium or other amounts when
due on any indebtedness described as specified senior indebtedness in the
subordinated indenture as may be modified by the applicable supplemental
indenture; or
- we default in performing any other covenant in any senior indebtedness if
the covenant default allows the holders of such specified senior
indebtedness to accelerate the maturity of the specified senior
indebtedness. (Section 1603)
A covenant default will prevent us from paying the subordinated debt
securities only for up to 179 days after the holders of the specified senior
indebtedness notify us and the trustee that a blockage period has begun. The
holders of
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specified senior indebtedness may only give one such notice during a 360 day
period. (Section 1603)
The subordination does not affect our obligation, which is absolute and
unconditional, to pay, when due, principal of, premium, if any, and interest on
the subordinated debt securities. In addition, the subordination does not
prevent the occurrence of any default under the subordinated indenture. (Section
1606).
The subordinated indenture will not limit the amount of senior debt that we
may incur. As a result of the subordination of the subordinated debt securities,
if we became insolvent, holders of subordinated debt securities may receive less
on a proportionate basis than other creditors.
Conversion
Under the subordinated indenture we may issue subordinated debt securities
which are convertible into or exchangeable for our common stock, preferred
stock, debt securities, other securities or property or securities or property
issued by another entity. Convertible subordinated debt securities will be
convertible on terms and at a conversion price described in the prospectus
supplement. (Section 301, 1501 and 1502) The subordinated indenture will provide
for adjustments in the conversion price if we make changes to our capital
structure. (Section 1504)
If the securities are convertible into our common stock, the conversion
price will be subject to change if any of the following events occur:
- we issue common stock as a dividend to our shareholders;
- we subdivide, combine or reclassify our common stock;
- we issue rights, which may be exercised for 45 days or less, to our
shareholders to purchase common stock at a price per share less than the
market price of the common stock at the time the rights are issued; or
- we distribute to our shareholders debt securities, equity securities or
assets, other than cash dividends paid from our surplus. (Section 1504)
Adjustments in the conversion price may have tax consequences. These tax
consequences, if applicable, will be described in the prospectus supplement. We
also will not issue fractional shares upon conversion, but will pay the value of
a fractional share to the person who would otherwise be entitled to receive such
payment. (Section 1503)
If we consolidate or merge with, or sell all or substantially all of our
assets to, another company, the convertible subordinated debt securities will be
convertible into the consideration that a holder of the convertible subordinated
debt securities would have received had the holder exercised the conversion
rights immediately before the consolidation, merger or sale. (Section 1505)
If a series of subordinated debt securities is convertible into anything
other than our common stock, the prospectus supplement will describe the
following:
- the events which will cause an adjustment in the conversion price;
- any related tax consequences of the adjustments in the conversion price;
- any special treatment of fractional shares; and
- the effect of a consolidation, merger or sale of all or substantially all
of our assets on the conversion rights.
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DESCRIPTION OF CAPITAL STOCK
Selected provisions of our organizational documents are summarized below.
The summary is not complete. You should read the organizational documents, which
are filed as exhibits to the registration statement, for other provisions that
may be important to you. In addition, you should be aware that the summary below
does not give full effect to the terms of the provisions of statutory or common
law which may affect your rights as a stockholder.
We are authorized to issue 20 million shares of common stock and 2.5
million shares of preferred stock. As of September 15, 1999, 8,557,906 shares of
common stock were outstanding and 1,045,461 shares of preferred stock were
outstanding. As of September 15, 1999, 255,492 shares of common stock were
reserved for issuance under our 1994 Stock Incentive Plan, 1996 Stock Incentive
Plan and the 1997 Employee Stock Purchase Plan.
COMMON STOCK
Listing
Our common stock is listed on the New York Stock Exchange under the symbol
"CPE." Any additional common stock that we issue will also be listed on the New
York Stock Exchange, unless otherwise indicated in a prospectus supplement.
Dividends
Shareholders may receive dividends declared by our board of directors if,
as and when our board of directors declares any such dividends. The indentures
for our existing subordinated debt and our loan agreements with banks contain
restrictions on the payment of dividends.
Fully Paid
All of our outstanding shares of common stock are fully paid and
non-assessable. Any additional shares of common stock will also be fully paid
and non-assessable.
Voting Rights
Each share of common stock is entitled to one vote in the election of
directors and other matters submitted to our shareholders. Our common stock does
not have cumulative or preemptive rights.
Other Provisions
We will notify holders of common stock of any shareholders' meetings in
accordance with applicable law. If we liquidate, dissolve or wind-up, whether
voluntarily or not, our common stockholders will share equally in the assets
remaining after we pay our creditors and holders of our preferred stock.
Transfer Agent and Registrar
American Stock Transfer and Trust Company is the registrar and transfer
agent for our common stock.
PREFERRED STOCK
The following description of the terms of the preferred stock sets forth
general terms and provisions of the preferred stock to which a prospectus
supplement may relate. Specific terms of any series of preferred stock offered
by a prospectus supplement will be described in the prospectus supplement
relating to such series. You should read the certificate of designations
establishing a particular series of preferred stock, which will be filed with
the SEC in connection with the offering of such series for other provisions that
may be important to you.
Our board of directors can, without approval of our shareholders, issue one
or more series of preferred stock. The board can also determine the number of
shares of each series and the rights, preferences, privileges and restrictions
including the dividend rights, voting rights, conversion rights, redemption
rights and any liquidation preferences of any series of preferred stock and the
terms and conditions of issue. In some cases, the issuance of preferred stock
could delay a change in the persons and entities controlling us and make it
harder to remove present management. Under certain circumstances, preferred
stock could also restrict dividend payments to holders of our common stock or
restrict our ability to repurchase or redeem shares while there is an arrearage
in the payment of dividends to the holders of preferred stock.
The preferred stock will, when issued, be fully paid and non-assessable.
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The transfer agent, registrar and dividend disbursement agent for a series
of preferred stock will be named in a prospectus supplement. The registrar for
preferred stock will send notices to shareholders of any meetings at which
holders of the preferred stock have the right to elect directors or to vote on
any other matter.
If we offer preferred stock, the specific terms of a particular series will
be described in the prospectus supplement, and will include the following:
- the maximum number of shares to constitute the series and the distinctive
designations of such series;
- the dividend rate, whether dividends will be paid in preference to
dividends on common stock, and whether dividends will be cumulative;
- whether and the manner in which the preferred stock will be redeemable;
- any liquidation preference applicable to the preferred stock;
- whether and the manner in which the preferred stock will be subject to a
retirement or sinking fund that requires us to repurchase the shares;
- any conversion rights applicable to the preferred stock;
- any restrictions on the ability to sell or transfer the preferred stock;
- any voting rights; and
- any other preferences or other special rights or limitations.
Series A Preferred Stock
In November 1995, we issued and sold 1,315,500 shares of series A preferred
stock.
Dividend Rights. Holders of the series A preferred stock are entitled to an
annual cash dividend of $2.125 per share, payable quarterly. If dividends are
not paid in full on all outstanding shares of the series A preferred stock and
any other security ranking on parity with the series A preferred stock,
dividends declared on the series A preferred stock and such other parity stock
are paid pro rata. Unless full cumulative dividends on all outstanding shares of
series A preferred stock have been paid, no dividends (other than in common
stock or other stock ranking junior to the series A preferred stock) may be
paid, or any other distributions made, on the common stock or on any other stock
of ours ranking junior to the series A preferred stock, nor may any common stock
or any other stock of ours ranking junior to or on a parity with the series A
preferred stock be redeemed, purchased or otherwise acquired for any
consideration by us (except by conversion into or exchange for stock of Callon
ranking junior to the series A preferred stock).
Conversion. The series A preferred stock is convertible at any time prior
to being called for redemption into common stock at a rate of approximately
2.273 shares of common stock for each share of series A preferred stock, subject
to adjustment for certain antidilutive events. From time to time, we may reduce
the conversion price by any amount for a period of at least 20 days if the board
of directors determines that such reduction is in our best interests. In the
event of certain changes in control or fundamental changes, holders of series A
preferred stock have the right to convert all of their series A preferred stock
into common stock at a rate equal to the average of the last reported sales
prices of the common stock for the five business days ending on the last
business day preceding the date of the change in control or fundamental change.
We or our successor may elect to distribute cash to such holders in lieu of
common stock at an equal value.
Exchange. The series A preferred stock may be exchanged at our option for
convertible debentures beginning on January 15, 1998 at the rate of $25
principal amount of convertible debentures for each share of preferred stock,
provided that all accrued and unpaid dividends have been paid and certain other
conditions are met. See "Convertible Debentures" below.
Redemption. On or after December 31, 1998, we may from time to time redeem
the series A preferred stock at an initial redemption price of $26.488. On
December 31 of each year thereafter and until December 31, 2005, the redemption
price decreases. On December 31, 2005 and thereafter, the redemption price shall
remain at $25.
Voting Rights. The holders of series A preferred stock have no voting
rights, except as otherwise provided by law. However, if dividend
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payments are in arrears in an amount equal to or exceeding six quarterly
dividends, the number of our directors will be increased by two and the holders
of the series A preferred stock (voting separately as a class) will be entitled
to elect the additional two directors until all dividends have been paid. In
addition, we may not create, issue or increase the authorized number of shares
of any class or series of stock ranking senior to the series A preferred stock
or alter, change or repeal any of the powers, rights or preferences of the
holders of the series A preferred stock as to adversely affect such powers,
rights or preferences.
Convertible Debentures. At our option, the series A preferred stock may be
converted into convertible debentures. The convertible debentures, if issued,
will be issued under an indenture between Callon and Bank One Columbus, NA, as
trustee, a copy of which is filed as an exhibit to our Form 10-K for fiscal year
1996. The convertible debentures will be our unsecured, subordinated
obligations, limited in aggregate principal amount to the aggregate liquidation
preference of the series A preferred stock and will mature on December 31, 2010.
We must pay interest on the convertible debentures semiannually following the
issue thereof at the rate of 8.5% per annum. The convertible debentures are to
be issued in fully registered form, without coupons, in denominations of $25 or
any integral multiple thereof.
In a December 1998 private transaction, a preferred stockholder elected to
convert 59,689 shares of preferred stock into 136,867 shares of our common
stock. Subsequent to December 31, 1998, several other preferred stockholders,
through private transactions, converted 210,350 shares of preferred stock into
502,632 shares of our common stock under similar terms.
STAGGERED BOARD OF DIRECTORS
Our certificate of incorporation and bylaws divide our board of directors
into three classes, as nearly equal in number as possible, serving staggered
three-year terms. The certificate of incorporation and bylaws also provide that
the classified board provision may not be amended without the affirmative vote
of the holders of 80% or more of the voting power of our capital stock. The
classification of the board of directors has the effect of requiring at least
two annual stockholder meetings, instead of one, to effect a change in control
of the board of directors, unless the articles of incorporation are amended.
DELAWARE ANTI-TAKEOVER STATUTE
We are a Delaware corporation and are subject to Section 203 of the
Delaware General Corporation Law. In general, Section 203 prevents us from
engaging in a business combination with an "interested stockholder" (generally,
a person owning 15% or more of our outstanding voting stock) for three years
following the time that person becomes a 15% stockholder unless either:
- before that person became a 15% stockholder, our board of directors
approved the transaction in which the stockholder became a 15%
stockholder or approved the business combination;
- upon completion of the transaction that resulted in the stockholder's
becoming a 15% stockholder, the stockholder owns at least 85% of our
voting stock outstanding at the time the transaction began (excluding
stock held by directors who are also officers and by employee stock plans
that do not provide employees with the right to determine confidentially
whether shares held subject to the plan will be tendered in a tender or
exchange offer); or
- after the transaction in which that person became a 15% stockholder, the
business combination is approved by our board of directors and authorized
at a stockholder meeting by at least two-thirds of the outstanding voting
stock not owned by the 15% stockholder.
Under the Section 203, these restrictions also do not apply to certain
business combinations proposed by a 15% stockholder following the disclosure of
an extraordinary transaction with a person who was not a 15% stockholder during
the previous three years or who became a 15% stockholder with the approval of a
majority of our directors. This exception applies only if the extraordinary
transaction is approved or not opposed by a majority of our directors who were
directors before any person became a 15% stockholder in the previous three
years, of the successors of these directors.
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LIMITATION ON DIRECTORS' LIABILITY
Delaware has adopted a law that allows corporations to limit or eliminate
the personal liability of directors to corporations and their stockholders for
monetary damages for breach of directors' fiduciary duty of care. The duty of
care requires that, when acting on behalf of the corporation, directors must
exercise an informed business judgment based on all material information
reasonably available to them. Absent the limitations allowed by the law,
directors are accountable to corporations and their stockholders for monetary
damages for acts of gross negligence. Although the Delaware law does not change
directors' duty of care, it allows corporations to limit available relief to
equitable remedies such as injunction or rescission. Our certificate of
incorporation limits the liability of our directors to the fullest extent
permitted by this law. Specifically, our directors will not be personally liable
for monetary damages for any breach of their fiduciary duty as a director,
except for liability
- for any breach of their duty of loyalty to the company or our
stockholders;
- for acts or omissions not in good faith or that involve intentional
misconduct or a knowing violation of law;
- under provisions relating to unlawful payments of dividends or unlawful
stock repurchases or redemptions; or
- for any transaction from which the director derived an improper personal
benefit.
This limitation may have the effect of reducing the likelihood of
derivative litigation against directors, and may discourage or deter
stockholders or management from bringing a lawsuit against directors for breach
of their duty of care, even though such an action, if successful, might
otherwise have benefitted our stockholders.
DESCRIPTION OF SECURITIES WARRANTS
We may issue securities warrants entitling the holder to purchase our debt
securities, preferred stock or common stock as described in the prospectus
supplement relating to the issuance of the securities warrants. Securities
warrants may be issued independently or together with other of our securities
and may be attached to or separate from other securities. The securities
warrants will be issued under warrant agreements to be entered into between us
and a bank or trust company that acts as warrant agent. The warrant agent will
act solely as our agent in connection with securities warrants and will not
assume any obligation or relationship of agency or trust for or with any holders
of securities warrants or beneficial owners of securities warrants.
The specific terms of any securities warrants will be described in the
applicable prospectus supplement.
INTRODUCTION
The prospectus supplement will describe the terms of any securities
warrants offered, including the following:
- the amount of securities warrants to be registered and the purchase price
and manner of payment to acquire the securities warrants;
- a description, including amount, of the debt securities, preferred stock
or common stock which may be purchased upon exercise;
- the exercise price which must be paid to purchase the securities upon
exercise of a securities warrant and any provisions for changes or
adjustments in the exercise price;
- any date on which the securities warrants and the related debt
securities, preferred stock or common stock will be separately
transferable;
- the dates on which the right to exercise the securities warrants shall
commence and expire;
- a discussion of certain U.S. federal income tax, accounting and other
special considerations, procedures and limitations relating to the
securities warrants; and
- any other material terms of the securities warrants.
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Holders of securities warrants will not have any of the rights of holders
of our debt securities, preferred stock or common stock that may be purchased
upon exercise until they exercise the securities warrants and receive the
underlying securities. These rights include the right to receive payments of
principal of, any premium on, or any interest on, the debt securities
purchasable upon such exercise or to enforce the covenants in the indentures or
to receive payments of dividends on the preferred stock or common stock which
may be purchased upon exercise or to exercise any voting right.
EXERCISE OF SECURITIES WARRANTS
After the close of business on the expiration date described in the
prospectus supplement, securities warrants will expire and the holders will no
longer have the right to exercise the securities warrants and receive the
underlying securities. Securities warrants may be exercised by delivering a
properly completed certificate in the form attached to the securities warrants
and payment of the exercise price as provided in the prospectus supplement. We
will issue and deliver our debt securities, preferred stock or common stock as
soon as possible following receipt of the certificate and payment described
above. If less than all of the securities warrants represented by a certificate
are exercised, we will issue a new certificate for the remaining securities
warrants. The foregoing terms of exercise may be modified by us in a prospectus
supplement.
DESCRIPTION OF SECURITIES PURCHASE CONTRACTS
AND SECURITIES PURCHASE UNITS AND PREPAID SECURITIES
We may also issue securities purchase contracts which obligate the holder
of the contracts to purchase, and obligate us to sell, our common stock or
preferred stock at one or more times in the future. The prospectus supplement
will describe the terms of any securities purchase contracts, including the
following to the extent applicable:
- whether the holder is obligated to purchase our common stock or preferred
stock, and the dates on which such shares must be purchased;
- the purchase price of the common stock or preferred stock, which may be
fixed at the time of issuance or determined in the future by a formula;
- any periodic payments that we must make to the holders of the securities
purchase contracts, or any periodic payments that the holders must make
to us and whether these periodic payments are unsecured or prefunded in
some manner; and
- any collateral that a holder of securities purchase contracts is
obligated to pledge to secure the holder's obligations to purchase
securities and make periodic payments under the contract.
Securities purchase contacts may be issued with our debt securities,
preferred stock or other securities as a unit, referred to as a "securities
purchase unit." If securities purchase units are issued, the debt securities,
preferred stock or other securities which are part of the units may be pledged
to secure the holder's obligation to purchase the common stock or preferred
stock and to make any periodic payments provided for in the securities purchase
contract. A securities purchase unit may also provide for the substitution of
U.S. Treasury securities or securities of other persons for the debt securities,
preferred stock or other securities initially issued as part of the securities
purchase units. Securities purchase units may also give a financial institution
or other person the right to purchase the debt securities, preferred stock or
other securities which are part of the securities purchase units. We may also
have the right or obligation to deliver newly issued prepaid securities purchase
contracts ("prepaid securities") upon release to a holder of any collateral
securing the holder's obligations under the original stock purchase contract.
Any such purchase rights will be described in a prospectus supplement.
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PLAN OF DISTRIBUTION
We may sell the securities
(1) through underwriters or dealers;
(2) through agents;
(3) directly to purchasers;
(4) through remarketing firms; or
(5) through a combination of any such methods of sale.
Any such underwriter, dealer or agent may be deemed to be an underwriter
within the meaning of the Securities Act of 1933.
UNDERWRITERS OR DEALERS
If underwriters are utilized in the sale, the securities will be acquired
by the underwriters for their own account. The underwriters may sell the
securities in one or more transactions, including negotiated transactions, at a
fixed public offering price or at varying prices determined at the time of sale.
The obligations of the underwriters to purchase the securities will be subject
to several conditions set forth in an agreement between us and the underwriters.
The underwriters will be obligated to purchase all of the securities offered if
any of the securities are purchased. Any public offering price and any discounts
or concessions allowed or re-allowed or paid to dealers may be changed from time
to time. We may grant underwriters who participate in the distribution of
securities an option to purchase additional securities if they sell more
securities than they purchased.
During and after an offering through underwriters, the underwriters may
purchase and sell the securities in the open market. These transactions may
include overallotment and stabilizing transactions and purchases to cover
syndicate short positions created in connection with the offering. The
underwriters may also impose a penalty bid, in which selling concessions allowed
to syndicate members or other broker-dealers for the offered securities sold for
their account may be reclaimed by the syndicate if such offered securities are
repurchased by the syndicate in stabilizing or covering transactions. These
activities may stabilize, maintain or otherwise affect the market price of the
offered securities, which may be higher than the price that might otherwise
prevail in the open market. If commenced, these activities may be discontinued.
If we use dealers in the sale of securities, we will sell the securities to
them as principals. They may then resell those securities to the public at
varying prices determined by the dealers at the time of resale. We will include
in the prospectus supplement the names of the dealers and the terms of the
transaction.
AGENTS
We may designate agents who agree to use their reasonable efforts to
solicit purchasers for the period of their appointment or to sell securities on
a continuing basis.
DIRECT SALES
We may also sell securities directly to one or more purchasers without
using underwriters or agents.
REMARKETING FIRMS
The securities may be re-sold to the public following their redemption or
repayment by one or more remarketing firms. Remarketing firms may act as
principals for their own accounts or as agents for us.
RIGHTS OFFERINGS; CONVERSIONS
If we were to issue rights on a pro rata basis to our shareholders, we may
be able to use this prospectus to offer and sell the securities underlying the
rights. We may also be able to use the prospectus to offer and sell securities
to be received upon conversion of any convertible securities we may issue or
upon exercise of transferable warrants that may be issued by us or an affiliate.
GENERAL INFORMATION
Underwriters, dealers, agents and remarketing firms that participate in the
distribution of the securities may be underwriters as defined in the Securities
Act of 1933, and any discounts or commissions received by them from us and any
profit on the resale of the securities by them may be treated as underwriting
discounts and commissions under the Securities Act of 1933. Any
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<PAGE> 90
underwriter, dealer, agent or remarketing firm will be identified and the terms
of the transaction, including their compensation, will be described in a
prospectus supplement. We may have agreements with underwriters, dealers, agents
or remarketing firms to indemnify them against certain liabilities, including
liabilities under the Securities Act of 1933, or to contribute with respect to
payments which the underwriters, dealers or agents may be required to make.
Underwriters, dealers, agents or remarketing firms, or their affiliates may be
customers of, engage in transactions with or perform services for, us or our
subsidiaries in the ordinary course of their business.
All debt securities will be new issues of securities with no established
trading market. Any underwriters to whom debt securities are sold by us for
public offering and sale may make a market in such securities, but such
underwriters will not be obligated to do so and may discontinue any market
making at any time without notice. No assurance can be given as to the liquidity
of the trading market for any debt securities.
We may use agents and underwriters to solicit offers by certain
institutions to purchase debt securities from us at the public offering price
set forth in the prospectus supplement pursuant to delayed delivery contracts
providing for payment and delivery on the date stated in the prospectus
supplement. Delayed delivery contracts will be subject to only those conditions
set forth in the prospectus supplement. A commission indicated in the prospectus
supplement will be paid to underwriters and agents soliciting purchases of debt
securities pursuant to delayed delivery contracts accepted by us.
EXPERTS
INDEPENDENT ACCOUNTANTS
The audited consolidated financial statements as of December 31, 1998 and
for the three years in the period ended December 31, 1998, incorporated by
reference elsewhere in this registration statement, have been audited by Arthur
Andersen LLP, independent public accountants, as indicated in their report with
respect thereto, and are incorporated by reference herein in reliance upon the
authority of said firm as experts in accounting and auditing in giving said
reports.
RESERVE ENGINEERS
The information incorporated by reference in this prospectus regarding our
quantities of oil and gas and future net cash flows and the present values
thereof from such reserves is based on estimates of such reserves and present
values prepared by Huddleston & Co., Inc., an independent petroleum and
geological engineering firm.
LEGAL MATTERS
The validity of the issuance of the securities will be passed upon for us
by our lawyers, Haynes and Boone, LLP, Houston, Texas. Counsel named in the
prospectus supplement will issue opinions about the validity of the securities
for any agents, dealers or underwriters.
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[MAP SHOWING AREAS OF DEEP WATER ACTIVITIES]
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WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT
CONTAINED IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. NEITHER
THE DELIVERY OF THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS NOR
SALE OF THE COMMON STOCK MEANS THAT INFORMATION CONTAINED IN THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS CORRECT AFTER THE DATES OF THIS
PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS ARE NOT AN OFFER TO SELL OR A
SOLICITATION OF AN OFFER TO BUY THESE SHARES OF COMMON STOCK IN ANY
CIRCUMSTANCES UNDER WHICH THE OFFER OR SOLICITATION IS UNLAWFUL.
---------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PROSPECTUS SUPPLEMENT PAGE
<S> <C>
Prospectus Supplement Summary.............. S-3
Risk Factors............................... S-9
Forward-Looking Statements................. S-16
Use of Proceeds............................ S-17
Price Range of Common Stock and Dividend
Policy................................... S-17
Capitalization............................. S-18
Selected Financial Data.................... S-19
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................... S-21
Business and Properties.................... S-28
Management................................. S-35
Beneficial Ownership of Our Common and
Preferred Stock.......................... S-37
Description of Capital Stock............... S-40
Description of Bank Credit Facility and
Other Indebtedness....................... S-41
Underwriting............................... S-43
Validity of the Common Stock............... S-44
Experts.................................... S-44
Glossary of Oil and Gas Terms.............. S-45
Index to Financial Statements.............. F-1
PROSPECTUS
About this Prospectus...................... 1
Where You Can Find More Information........ 1
Disclosure Regarding Forward-Looking
Statements............................... 2
About Callon Petroleum Company............. 2
Use of Proceeds............................ 2
Ratio of Earnings to Fixed Charges and of
Earnings to Combined Fixed Charges and
Preferred Stock Dividends................ 3
Description of Debt Securities............. 3
Description of Capital Stock............... 14
Description of Securities Warrants......... 17
Description of Securities Purchase
Contracts and Securities Purchase Units
and Prepaid Securities................... 18
Plan of Distribution....................... 19
Experts.................................... 20
Legal Matters.............................. 20
</TABLE>
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3,200,000 SHARES
[LOGO]
CALLON PETROLEUM COMPANY
COMMON STOCK
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PROSPECTUS SUPPLEMENT
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A.G. EDWARDS & SONS, INC.
HOWARD, WEIL, LABOUISSE,
FRIEDRICHS
INCORPORATED
JOHNSON RICE & COMPANY L.L.C.
MORGAN KEEGAN & COMPANY, INC.
, 1999
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