<PAGE> 1
FILED PURSUANT TO RULE 424(B)(2)
REGISTRATION NO. 333-87945
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED OCTOBER 6, 1999)
$32,000,000
CALLON PETROLEUM COMPANY
[CALLON LOGO]
11% SENIOR SUBORDINATED NOTES DUE 2005
------------------------
INVESTING IN THE NOTES INVOLVES RISKS.
SEE "RISK FACTORS" BEGINNING ON PAGE S-10.
------------------------
TERMS OF NOTES
- MATURITY
December 15, 2005.
- INTEREST
Fixed annual rate of 11%.
We will pay interest on the notes on March 15, June 15, September 15 and
December 15 of each year. The first interest payment will be made on December
15, 2000, which will represent interest accrued from October 26, 2000.
- TRADING
The notes have been approved for listing on the New York Stock Exchange.
- OPTIONAL REDEMPTION
We may redeem the notes at any time on or after March 15, 2003 at 100% of
their principal amount plus accrued and unpaid interest.
- RANKING
The notes are subordinated in right of payment to all of our senior debt and
the obligations of our subsidiaries. The notes rank equally with our existing
and future senior subordinated indebtedness. The notes are senior to our
outstanding preferred stock.
- CHANGE OF CONTROL
If a change of control occurs, we must offer to repurchase the notes at 101%
of their principal amount plus accrued and unpaid interest.
<TABLE>
<CAPTION>
PER NOTE TOTAL
-------- -----------
<S> <C> <C>
Public offering price....................................... 100.0% $32,000,000
Underwriting discount....................................... 3.5% $ 1,120,000
Proceeds, before expenses................................... 96.5% $30,880,000
</TABLE>
Callon Petroleum Company has granted the underwriters the right to purchase
up to an additional $4,800,000 aggregate principal amount of notes to cover
over-allotments.
The underwriters expect to deliver the notes in book-entry form only
through the facilities of The Depository Trust Company against payment in New
York, New York on October 26, 2000.
Neither the Securities and Exchange Commission nor any state security
commission has approved or disapproved 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.
------------------------
MORGAN KEEGAN & COMPANY, INC. A.G. EDWARDS & SONS, INC.
Prospectus supplement dated October 23, 2000.
<PAGE> 2
[MAP SHOWING PRINCIPAL AREAS OF OPERATIONS IN THE GULF OF MEXICO]
OIL AND GAS PROPERTIES
<TABLE>
<CAPTION>
DECEMBER 31, 1999
--------------------------------------------------------
PERCENT
ESTIMATED NET PROVED RESERVES DISCOUNTED TOTAL
------------------------------ PRESENT DISCOUNTED
GAS OIL TOTAL VALUE PRESENT
(MMCF) (MBBLS) (MMCFE) ($000) VALUE
-------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Gulf of Mexico Shelf Area.................. 75,530 299 77,322 $ 89,966 30.3%
Gulf of Mexico Deep Water Area............. 34,326 22,458 169,071 185,802 62.7%
Onshore.................................... 6,579 1,077 13,048 20,745 7.0%
------- ------ ------- -------- -----
Total............................ 116,435 23,834 259,441 $296,513 100.0%
======= ====== ======= ======== =====
</TABLE>
<PAGE> 3
PROSPECTUS SUPPLEMENT SUMMARY
This summary highlights information from this prospectus supplement, but
does not contain all 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
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, unless the
context otherwise requires. If you are not familiar with the terms used to
describe the quantities, present value and other information about oil and gas
reserves, please see "Glossary of Oil and Gas Terms."
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. Our senior
management has worked together for over 20 years. In addition, we have 12
engineering and geoscience professionals with an average of 12 years of
experience with us. We have historically grown our reserves and production by
focusing primarily on low to moderate risk exploration and acquisition
opportunities in the Gulf of Mexico shelf area. Over the last several years, we
have expanded our 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 three additional deep water discoveries on our
Habanero, Medusa and Entrada prospects.
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 December 31, 1999, estimated net proved
reserves increased 345%.
- As of December 31, 1999, we had estimated net proved reserves of 259.4
Bcfe which had a discounted present value of $296.5 million. Reserves
comprising 37% of this discounted present value were classified as proved
developed.
- Net proved reserves as of December 31, 1999 divided by our production
from the four quarters ended June 30, 2000, which we refer to as our
"reserve life," was 15.7 years.
- Average daily net production increased 86% from the first quarter of 1996
to the second quarter of 2000.
- Average daily net production during the first half of 2000 was 42.8
MMcfe, of which 90% was natural gas. We operate wells representing
approximately 73% of this production.
- Our reserve replacement costs for the period January 1, 1996 to December
31, 1999 were $.80 per Mcfe.
BUSINESS STRATEGY
Our goal is to increase shareholder value by increasing our reserves,
production, cash flow and earnings. We seek to achieve these goals through the
following strategies:
- Focus on Gulf of Mexico exploration with a balance between shelf and deep
water areas using the latest available technology.
- Aggressively explore our existing prospect inventory.
- Replenish our prospect inventory with increasing emphasis on prospect
generation.
S-3
<PAGE> 4
- Achieve moderate increases in current production levels through continued
shelf exploration.
- Achieve significant increases in longer-term production levels through
development of deep water discoveries and ongoing deep water exploration.
- Maintain financial flexibility.
EXPLORATION OPERATIONS
We explore for oil and gas in the state and federal waters of the Gulf of
Mexico. Since 1996, we have drilled 16 gross (10.2 net) productive exploration
wells and 15 gross (6.6 net) dry holes in the Gulf of Mexico for a gross success
rate of 51.6% (60.7% net). We have also drilled six gross (3.1 net) development
wells in the Gulf of Mexico, all of which were successful. We currently have two
gross (.3 net) wells in progress. Our principal areas of exploration are
summarized below. See "Business and Properties."
Gulf of Mexico Shelf Area. We explore for oil and gas deposits in the shelf
area of the Gulf of Mexico using the latest in 3-D seismic technology. Our
weighted average working interest in productive wells in the Gulf of Mexico
shelf area is 84.6% and we operated 86% of our average daily production during
the first half of 2000. Since 1996, we have drilled 25 gross (15.6 net)
exploration wells in this area, of which 12 gross (9.3 net) were productive. We
also drilled five gross (2.9 net) development wells, all of which were
successful. We currently have an inventory of 12 exploration prospects in this
area, four of which we expect to drill in 2000. In addition to these prospects,
in August 2000 we were the apparent high bidder on six blocks in the Gulf of
Mexico shelf area. Two of these blocks have been awarded and four are subject to
approval by the Minerals Management Service.
Gulf of Mexico Deep Water Area. We also explore the deep water area of 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, BP Amoco and Murphy Exploration
and Production, as operators. Since 1998, we have drilled six gross (.8 net)
exploration wells in our deep water area, of which four gross (.5 net) were
successful. We have also drilled one gross (.2 net) development well which was
successful. We currently have in progress one gross (.1 net) exploratory well
and one gross (.2 net) development well. In September 1998, we announced our
first deep water discovery on our Boomslang prospect, and in February 1999, we
announced a deep water discovery on our Habanero prospect. In September 1999, we
announced a deep water discovery on our Medusa prospect. These discoveries
represent the largest discoveries in our history and have added estimated net
proved reserves of 148.6 Bcfe at December 31, 1999. In April 2000, we announced
a deep water discovery on our Entrada prospect. We currently have an inventory
of 23 deep water exploration prospects, five of which we expect to drill in
2000.
S-4
<PAGE> 5
RECENT DEVELOPMENTS
GULF OF MEXICO SHELF AREA ACTIVITIES
In November 1999, we announced a discovery on South Marsh Island Block 261,
located in the Gulf of Mexico shelf area, which encountered 110 feet of net
natural gas pay. A second test well encountered 100 feet of net natural gas pay
before it blew out on January 2, 2000. We brought the well under control,
plugged it and drilled a replacement well in the first quarter of 2000.
Insurance covered the costs associated with the blowout and the replacement
well. Currently, these two wells produce an average of 19.7 MMcfe per day. A
fourth well, which we completed drilling in the second quarter of 2000, is
scheduled to commence production in the first half of 2001. We own a 100%
working interest in the block.
In December 1999, we announced a discovery on East Cameron Block 275,
located in the Gulf of Mexico shelf area. Production from the well began in
April 2000 and the well is currently producing an average of 5.2 MMcfe per day.
We own a 100% interest in the block.
GULF OF MEXICO DEEP WATER AREA ACTIVITIES
In September 1999, we announced a deep water discovery on our Medusa
prospect. The discovery, our third deep water discovery, added estimated net
proved reserves at December 31, 1999 of 61.8 Bcfe with a discounted present
value of $65.3 million. We drilled a second successful well on this prospect in
the first quarter of 2000 to further delineate the extent of the pay intervals.
We own a 15% working interest in the well and Murphy, the operator, owns a 60%
working interest.
In December 1999, we entered into an agreement to acquire a 20% working
interest in Garden Banks Blocks 782, 785, 826 and 827 from Vastar Resources,
Inc., now BP Amoco, for $3.2 million. We announced our fourth deep water
discovery, Entrada, located on Garden Banks Blocks 782, 826 and 827, in April
2000. The initial exploratory well encountered over 360 feet of pay in four
intervals. We are currently evaluating a delineation well that we drilled on
this prospect in the third quarter of 2000. BP Amoco is the operator and owns
the remaining 80% working interest. We have scheduled to drill our Cirrus
prospect on Garden Banks Block 785 in the summer of 2001.
We began drilling our Cumberland prospect, located in the deep water area
on Green Canyon Block 297, in August 2000. We plan to drill the well to a depth
of 16,750 feet, and we expect to reach total depth in October 2000. We own a
7.5% working interest in the prospect and, AGIP, the operator, owns a 55%
working interest. Murphy owns the balance.
PROPERTY ACQUISITIONS
In March 2000 we, along with Murphy, were the high bidder on East Cameron
Block 374, which is located in the Gulf of Mexico shelf area, and Mississippi
Canyon Block 493, which is located in the Gulf of Mexico deep water area. Both
blocks have been awarded by the Minerals Management Service.
In August 2000, we, on our own and participating with partners, were the
apparent high bidder on eight Gulf of Mexico tracts, of which six are located in
the shelf area and two are located in the deep water area. Three blocks have
been awarded, and the remaining five are subject to approval by the Minerals
Management Service.
PRINCIPAL OFFICE
Our principal executive offices are located at 200 North Canal Street,
Natchez, Mississippi 39120 and our telephone number is (601) 442-1601.
S-5
<PAGE> 6
THE OFFERING
Securities Offered......... $32,000,000 principal amount of 11% senior
subordinated notes due 2005. We have also granted
the underwriters the right to purchase up to an
additional $4,800,000 of notes to cover
over-allotments.
Maturity Date.............. December 15, 2005.
Interest Payment Dates..... March 15, June 15, September 15 and December 15.
The first interest payment will be on December 15,
2000, which will represent interest accrued from
October 26, 2000.
Optional Redemption........ On or after March 15, 2003, we may redeem all or a
portion of the notes at 100% of their principal
amount plus accrued and unpaid interest.
Ranking.................... The notes:
- are unsecured;
- rank junior to our existing and future senior
debt, including debt we may incur under our bank
credit facility and the liabilities of our
subsidiaries;
- rank equally with our existing and future senior
subordinated debt; and
- are senior to our outstanding preferred stock.
Assuming we had issued the notes and applied the
proceeds as intended as of June 30, 2000, we would
have had $15.6 million of senior indebtedness and
$108.0 million of senior subordinated indebtedness,
including the notes. Also, our subsidiaries had
$29.5 million of liabilities on their balance
sheets at June 30, 2000, excluding guarantees of
our bank debt.
Change of Control.......... If a change of control occurs, we must offer to
repurchase the notes at 101% of the principal
amount plus accrued and unpaid interest. For a
description of the change of control provisions,
see "Description of the Notes -- Certain
Covenants -- Change of Control."
Restrictive Covenants...... The indenture governing the notes contains
covenants that limit our ability and the ability of
our subsidiaries to:
- incur additional indebtedness;
- place liens on our assets;
- make dividend payments on our common stock or
repurchase any of our capital stock;
- enter into transactions with our affiliates; and
- merge, consolidate or sell substantially all of
our assets.
We fully disclose these covenants under
"Description of the Notes -- Certain Covenants."
Use of Proceeds............ We will use the net proceeds we receive from the
sale of the notes to purchase our outstanding 10%
senior subordinated notes due 2001 in connection
with a tender offer we are now making for the
notes. In addition, we plan to redeem all of our
10% senior subordinated notes
S-6
<PAGE> 7
not tendered in the offer. We will use any
additional proceeds, together with our cash flows
and borrowings under our bank credit facility, to
fund our remaining 2000 capital expenditure budget.
Pending this use of the net proceeds, we will repay
amounts under our bank credit facility, which may
be reborrowed at a later date.
Trading.................... The notes have been approved for listing on the New
York Stock Exchange.
S-7
<PAGE> 8
SUMMARY FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
The following is our summary financial data. For further information that
will help you better understand the summary data, see "Selected Financial Data"
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales..................... $ 23,760 $ 16,537 $ 37,140 $ 35,624 $ 42,130
Interest and other.................... 1,074 868 1,853 2,094 1,508
-------- -------- -------- -------- --------
Total revenues................ 24,834 17,405 38,993 37,718 43,638
-------- -------- -------- -------- --------
Costs and expenses:
Lease operating expenses.............. 4,154 3,486 7,536 7,817 8,123
Depreciation, depletion and
amortization....................... 8,317 7,952 16,727 19,284 16,488
General and administrative............ 1,972 2,440 4,575 5,285 4,433
Interest.............................. 3,846 2,471 6,175 1,925 1,957
Accelerated vesting and retirement
benefits........................... -- -- -- 5,761 --
Impairment of oil and gas
properties......................... -- -- -- 43,500 --
-------- -------- -------- -------- --------
Total costs and expenses...... 18,289 16,349 35,013 83,572 31,001
-------- -------- -------- -------- --------
Income (loss) from operations........... 6,545 1,056 3,980 (45,854) 12,637
Income tax expense (benefit).......... 2,226 359 1,353 (15,100) 4,200
-------- -------- -------- -------- --------
Net income (loss)....................... 4,319 697 2,627 (30,754) 8,437
Preferred stock dividends............... 1,105 1,386 2,497 2,779 2,795
-------- -------- -------- -------- --------
Net income (loss) available to common
shares................................ $ 3,214 $ (689) $ 130 $(33,533) $ 5,642
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic................................. $ .26 $ (.08) $ .01 $ (4.17) $ .91
Diluted............................... $ .26 $ (.08) $ .01 $ (4.17) $ .88
STATEMENT OF CASH FLOWS DATA:
Cash provided by operating activities... $ 8,950 $ 9,322 $ 21,197 $ 29,705 $ 27,337
Cash used in investing activities....... (55,318) (26,366) (51,709) (53,592) (81,549)
Cash provided by financing activities... 21,027 18,078 58,883 14,590 62,140
BALANCE SHEET DATA (END OF PERIOD):
Working capital (excluding current
maturities of debt)................... $ 3,267 $ 2,368 $ 20,493 $ 1,142 $ 12,719
Oil and gas properties, net............. 237,142 173,567 194,365 141,905 150,494
Total assets............................ 283,397 211,826 259,877 181,652 190,421
Total debt.............................. 122,250 101,013 100,250 81,250 60,250
Stockholders' equity.................... 127,985 82,400 124,380 84,484 113,701
OTHER FINANCIAL DATA:
Capital expenditures, net............... $ 51,253 $ 39,453 $ 68,865 $ 54,196 $ 85,159
EBITDA.................................. $ 19,643 $ 12,154 $ 28,369 $ 27,564 $ 33,209
Cash interest paid...................... $ 5,110 $ 3,815 $ 9,013 $ 6,229 $ 4,167
Ratio of EBITDA to cash interest paid... 3.5x 3.4x 3.1x 4.4x 8.0x
Ratio of earnings to fixed charges...... 1.8x -- 1.1x -- 3.3x
Ratio of total debt to EBITDA........... 3.4x 4.3x 3.5x 2.9x 1.8x
</TABLE>
S-8
<PAGE> 9
SUMMARY OPERATING AND RESERVE DATA
The following is our summary operating and reserve data. For further
information that will help you better understand the summary data, see "Selected
Financial Data."
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
----------------- ---------------------------
2000 1999 1999 1998 1997
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls)...................................... 130 176 330 310 462
Gas (MMcf)....................................... 7,005 6,843 14,606 14,036 13,114
Total production (MMcfe)............... 7,788 7,898 16,589 15,894 15,887
AVERAGE SALES PRICE:
Oil (per Bbl).................................... $26.58 $11.96 $ 12.16 $ 12.41 $ 18.63
Gas (per Mcf).................................... 2.90 2.11 2.27 2.26 2.56
Total production (per Mcfe)............ 3.05 2.09 2.24 2.24 2.65
AVERAGE COSTS (PER MCFE):
Lease operating expenses (excluding severance
taxes)......................................... $ .47 $ .38 $ .39 $ .44 $ .42
Severance taxes.................................. .06 .06 .07 .06 .09
Depreciation, depletion and amortization......... 1.05 1.01 .99 1.19 1.02
General and administrative (net of management
fees).......................................... .25 .31 .28 .33 .28
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
ESTIMATED NET PROVED RESERVES:
Oil (MBbls)................................................. 23,834 6,898 3,402
Gas (MMcf).................................................. 116,435 88,030 88,738
Gas equivalent (MMcfe)...................................... 259,439 129,418 109,150
Estimated future net cash flows before income taxes
(000s).................................................... $528,659 $152,552 $209,260
Discounted present value (000s)............................. $296,513 $ 99,751 $136,448
OTHER RESERVE DATA:
Reserve replacement costs ($/Mcfe).......................... $ .46 $ 1.29 $ 1.45
Reserve life (years)........................................ 15.6 8.1 6.9
</TABLE>
We compute natural gas equivalents on an approximate energy equivalent
basis so that one Bbl of oil equals six Mcf of gas.
S-9
<PAGE> 10
RISK FACTORS
You should carefully consider all of the information we have included in
this prospectus supplement, the prospectus and the documents we have
incorporated by reference before purchasing our notes.
RISK FACTORS RELATING TO OUR BUSINESS
OIL AND GAS PRICES ARE VOLATILE.
Our success is highly dependent on prices for oil and gas, which are
extremely volatile. Any substantial or extended decline in the price of oil or
gas would have a material adverse effect on us. Oil and gas markets are both
seasonal and cyclical. The prices of oil and gas depend on factors we cannot
control such as weather, economic conditions, levels of production, actions by
OPEC and other countries and government actions. Prices of oil and gas will
affect the following aspects of our business:
- our revenues, cash flows and earnings;
- our ability to attract capital to finance our operations and the cost of
the capital;
- the amount we are allowed to borrow under our bank credit facility;
- the value of our oil and gas properties; and
- the profit or loss we incur in exploring for and developing our reserves.
WE MAY BE UNABLE TO REPLACE RESERVES WHICH WE HAVE PRODUCED.
Our future success depends upon our ability to find, develop and acquire
oil and gas reserves that are economically recoverable. As is generally the case
in the Gulf Coast region, our producing properties usually have high initial
production rates, followed by a steep decline in production. As a result, we
must locate and develop or acquire new oil and gas reserves to replace those
being depleted by production. We must do this even during periods of low oil and
gas prices when it is difficult to raise the capital necessary to finance these
activities. Without successful exploration or acquisition activities, our
reserves, production and revenues will decline rapidly. We cannot assure you
that we will be able to find and develop or acquire additional reserves at an
acceptable cost.
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.
A SIGNIFICANT PART OF THE VALUE OF OUR PRODUCTION AND RESERVES IS CONCENTRATED
IN A SMALL NUMBER OF OFFSHORE PROPERTIES, AND ANY PRODUCTION PROBLEMS OR
INACCURACIES IN RESERVE ESTIMATES RELATED TO THOSE PROPERTIES WOULD ADVERSELY
IMPACT OUR BUSINESS.
For the three months ended June 30, 2000, about 63% of our daily production
came from three of our properties in the Gulf of Mexico. Moreover, one property
accounted for 35% of our daily production during this period. If mechanical
problems, storms or other events curtailed a substantial portion of this
production, our results of operations would be adversely affected. In addition,
at December 31, 1999 most of our proved reserves were located on ten fields in
the Gulf of Mexico, with approximately 88% of our total net proved reserves
attributable to five of these discoveries. If the actual reserves associated
with any one of these five discoveries are less than our estimated reserves, our
results of operations and financial condition could be adversely affected.
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 or at an
acceptable cost.
S-10
<PAGE> 11
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 materially reduce the value of our properties.
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 shallow 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. Our deep water
discoveries and prospects will require the construction of expensive production
facilities and pipelines prior to the beginning of production. We cannot
estimate the costs and timing of the construction of these facilities with
certainty, and the accuracy of our estimates will be affected by a number of
factors beyond our control, including the following:
- 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 present value of reserves
attributable to those prospects.
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.
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<PAGE> 12
Our competitors include major integrated oil companies and large
independent energy companies, many of which have greater financial and other
resources.
OUR COMPETITORS MAY USE SUPERIOR TECHNOLOGY WHICH WE MAY BE UNABLE TO AFFORD OR
WHICH WOULD REQUIRE COSTLY INVESTMENT BY US IN ORDER TO COMPETE.
Our industry is subject to rapid and significant advancements in
technology, including the introduction of new products and services using new
technologies. As our competitors use or develop new technologies, we may be
placed at a competitive disadvantage, and competitive pressures may force us to
implement new technologies at a substantial cost. In addition, our competitors
may have greater financial, technical and personnel resources that allow them to
enjoy technological advantages and may in the future allow them to implement new
technologies before we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us.
One or more of the technologies that we currently use or that we may implement
in the future may become obsolete, and we may be adversely affected. For
example, marine seismic acquisition technology has been characterized by rapid
technological advancements in recent years, and further significant
technological developments could substantially impair our 3-D seismic data's
value.
WE MAY NOT BE ABLE TO REPLACE OUR RESERVES OR GENERATE CASH FLOWS IF WE ARE
UNABLE TO RAISE CAPITAL.
We will be required to make substantial capital expenditures to develop our
existing reserves, and to discover new oil and gas reserves. Historically, we
have financed these expenditures primarily with cash from operations, proceeds
from bank borrowings and proceeds from the sale of debt and equity securities.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- 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.
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 in situations where 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 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;
S-12
<PAGE> 13
- 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. These 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.
On December 31, 1999, approximately 63% of the discounted present value of
our estimated net proved reserves were proved undeveloped.
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 failures which curtail or stop production;
and
- we could experience blowouts or other damages to the productive
formations that may require a well to be re-drilled or other corrective
action to be taken.
In addition, any of the foregoing may result in environmental damages for
which we will be liable. Moreover, a substantial portion of our operations are
offshore and are subject to a variety of risks peculiar to the marine
environment such as 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.
S-13
<PAGE> 14
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.
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. Also, we do not believe that insurance coverage for the
full potential liability that could be caused by sudden and accidental
environmental damages is available at a reasonable cost. Accordingly, we may be
subject to liability or we may be required to cease production from properties
in the event of environmental damages.
FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION.
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.
S-14
<PAGE> 15
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.
RISK FACTORS RELATED TO THE OFFERING
OUR SIGNIFICANT DEBT LEVELS AND OUR DEBT COVENANTS MAY LIMIT OUR FUTURE
FLEXIBILITY IN OBTAINING ADDITIONAL FINANCING AND IN PURSUING BUSINESS
OPPORTUNITIES.
Assuming we had issued the notes and applied the proceeds as described in
"Use of Proceeds" as of June 30, 2000, we would have had approximately $123.6
million in long-term debt. The level of our indebtedness will have important
effects on our future operations, including:
- A portion of our cash flow will be used to pay interest and principal on
our debt and will not be available for other purposes.
- Our bank credit facility contains financial tests which we must satisfy
in order to continue to borrow funds under the facility. Failure to meet
these tests may be a default under our bank credit facility.
- Covenants in the notes and in our existing senior subordinated notes
require us to meet financial tests in order to borrow additional money,
which may have the effect of limiting our flexibility in reacting to
changes in our business and our ability to fund future operations and
acquisitions.
- Our ability to refinance existing debt or to obtain additional financing
for capital expenditures and other purposes may be limited.
- We may be more leveraged than our competitors, which may place us at a
competitive disadvantage.
- 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 our business or general economic
conditions.
WE MAY NOT BE ABLE TO GENERATE SUFFICIENT CASH FLOW TO SERVICE OUR EXISTING
INDEBTEDNESS.
At June 30, 2000, after giving pro forma effect to the offering, we would
have had total indebtedness of approximately $123.6 million, and cash and cash
equivalents of $9.3 million. We intend to incur additional indebtedness after
the offering as we execute our business strategy.
Our ability to make scheduled payments or to refinance our indebtedness,
including $36.0 million of our 10.125% senior subordinated notes due 2002 and
our bank credit facility, 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."
WE MAY NOT HAVE SUFFICIENT ASSETS TO PAY AMOUNTS OWED ON THE NOTES IF A DEFAULT
OCCURS.
The notes will be subordinated to our current and future senior debt. In
addition, the notes will rank equally with our existing and future senior
subordinated indebtedness and will be subordinated to the obligations of our
subsidiaries. As of June 30, 2000, we had $22.1 million of senior debt and our
subsidiaries had liabilities of $29.5 million. Upon a liquidation or in a
bankruptcy or other similar proceeding, the holders of our senior debt will be
entitled to be paid in full before any payment may be made to you. In addition,
creditors of our subsidiaries will be paid prior to any use of our subsidiaries'
assets to make payments on the notes. As a result, you may receive less,
proportionately, than the holders of senior debt and our subsidiaries'
creditors. We cannot make any assurances that we will have sufficient assets to
pay amounts due on the notes. Our indenture for the notes permits us to incur
additional debt in the future, including the entire amount that will be
available for borrowing under our bank credit facility.
S-15
<PAGE> 16
If a default were to occur under our bank credit facility or other senior
indebtedness, the lenders could require us to repay all borrowings outstanding
under our bank credit facility or other senior indebtedness 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. We have included a more thorough discussion of the
covenants in our bank credit facility and existing senior subordinated notes
under "Description of Bank Credit Facility and Other Indebtedness."
WE MAY NOT BE ABLE TO REPURCHASE NOTES UPON A CHANGE OF CONTROL.
If a change of control occurs, you will have the right to require us to
repurchase all or any part of your notes as described under "Description of the
Notes -- Certain Covenants -- Change of Control." Our bank credit facility
prohibits the repurchase of the notes. In order to repurchase the notes, we
would be required to repay our debt under our bank credit facility or obtain
consents from our bank lenders. If we cannot repay the bank credit facility or
obtain the consents, we would not be able to repurchase the notes. Also, we may
not have sufficient funds available or be able to obtain the financing necessary
to repurchase the notes.
If a change of control occurs and we do not offer to repurchase the notes
or if we do not repurchase the notes when we are required to, an event of
default will occur under the indenture governing the notes, which would also be
a default under our bank credit facility and other senior subordinated notes.
Each of these defaults could have a material adverse effect on us and you.
THERE MAY NOT BE A LIQUID MARKET FOR RESALE OF THE NOTES.
The notes will be new securities for which currently there is no trading
market. The notes have been approved for listing on the New York Stock Exchange,
but we cannot assure you that a market for the notes will develop, or that the
market will have sufficient liquidity to enable resale of the notes.
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
these 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; and
- prospect development and property acquisitions.
Some of the risks which could affect our future results and could cause
results to differ materially from those expressed in our forward-looking
statements include:
- general economic conditions;
- volatility of oil and natural gas prices;
- uncertainty of estimates of oil and natural gas reserves;
S-16
<PAGE> 17
- impact of competition;
- availability and cost of seismic, drilling and other equipment;
- operating hazards inherent in the exploration for and production of oil
and natural gas;
- difficulties encountered during the exploration for and production of oil
and natural gas;
- difficulties encountered in delivering oil and natural gas to commercial
markets;
- changes in customer demand;
- uncertainty of our ability to attract capital;
- compliance with, or the effect of changes in, the extensive governmental
regulations regarding the oil and natural gas business;
- actions of operators of our oil and gas properties; and
- climatic 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 these 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.
USE OF PROCEEDS
We will receive approximately $30.6 million of net proceeds from this
offering ($35.3 million if the underwriters' over-allotment option is exercised
in full) after deducting the underwriters' discount and estimated offering
expenses. The net proceeds we receive from the sale of the notes will be used to
purchase our outstanding 10% senior subordinated notes due 2001 in connection
with a tender offer we are now making for these notes. In addition, we intend to
redeem all of our 10% senior subordinated notes not tendered in the offer. Total
cost to purchase and, if necessary, redeem the notes is $24.2 million, plus
accrued interest and expenses. Any additional proceeds, together with our cash
flows and borrowings under our bank credit facility, will be used to fund our
remaining 2000 capital expenditure budget. Pending the use of the net proceeds,
we will repay amounts under our bank credit facility, which may be reborrowed at
a later date. The weighted average interest rate on borrowings under our bank
credit facility on September 1, 2000 was 8.75%. Our existing bank credit
facility matures on October 31, 2000. Borrowings under our bank credit facility
were used to fund our capital expenditure budget.
S-17
<PAGE> 18
CAPITALIZATION
The following table sets forth our capitalization as of June 30, 2000 and
as adjusted, to give effect to the sale of notes and the application of the
estimated net proceeds.
For a description of the application of the net proceeds, see "Use of
Proceeds." You should read this information in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the consolidated financial statements and notes thereto included and
incorporated by reference in this prospectus supplement. As of September 15,
2000, the outstanding balance under our bank credit facility was $26.1 million.
<TABLE>
<CAPTION>
JUNE 30, 2000
---------------------------
HISTORICAL AS ADJUSTED(1)
---------- --------------
(IN THOUSANDS, EXCEPT SHARE
DATA)
<S> <C> <C>
Long-term debt:
Credit facility........................................... $ 22,100 $ 15,620
10% senior subordinated notes............................. 24,150 --
10.125% senior subordinated notes......................... 36,000 36,000
10.25% senior subordinated notes.......................... 40,000 40,000
The notes offered hereby.................................. -- 32,000
Stockholders' equity:
Preferred stock, $.01 par value, 2,500,000 shares
authorized; 1,040,461 shares of convertible
exchangeable preferred stock, series A issued and
outstanding with a liquidation preference of
$26,011,525............................................ 10 10
Common stock, $.01 par value, 20,000,000 shares
authorized; 12,277,211 shares issued and outstanding... 123 123
Treasury stock............................................ (1,183) (1,183)
Capital in excess of par value............................ 149,817 149,817
Retained earnings (deficit)............................... (20,782) (20,782)
-------- --------
Total stockholders' equity........................ 127,985 127,985
-------- --------
Total capitalization.............................. $250,235 $251,605
======== ========
</TABLE>
---------------
(1) Assumes the underwriters' over-allotment option is not exercised.
S-18
<PAGE> 19
SELECTED FINANCIAL DATA
The following table shows selected financial data for the five years ended
December 31, 1999 and for the six months ended June 30, 2000 and 1999. The
financial data for each of the three years in the period ended December 31, 1999
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, 1996 and 1995
has been derived from our audited financial statements. The financial data for
each of the six-month periods ended June 30, 2000 and 1999 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 prospectus supplement. 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.
- EBITDA is net income before interest expense, income tax expense,
depreciation, depletion, amortization and other non-cash charges. EBITDA
is presented because it is a widely accepted financial indication of a
company's ability to service and incur debt. EBITDA should not be
considered as an alternative to earnings (loss) as an indicator of our
operating performance or to cash flow as a measure of liquidity.
- EBITDA, used in the total debt to EBITDA ratio and the EBITDA to cash
interest paid ratio, is calculated using EBITDA for the immediately
preceding four quarters, including the interim periods.
- For purposes of computing the ratio of earnings to fixed charges,
"earnings" consist of the following:
- consolidated earnings or loss from continuing operations before income
tax, excluding undistributed equity earnings of affiliated companies;
plus
- fixed charges, excluding capitalized interest.
Fixed charges consist of the following:
- interest expense on indebtedness and capitalized interest;
- amortization of debt issuance costs, discounts and premiums; and
- that portion of capital lease expense which is deemed to be
representative of an interest factor.
Earnings did not cover fixed charges by $679,000 in the first half of 1999
and $50.3 million in 1998.
- 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. We describe the process
used to calculate the standardized measure under "Glossary of Oil and Gas
Terms."
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<PAGE> 20
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ----------------------------------------------------
2000 1999 1999 1998 1997 1996 1995
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales.............. $ 23,760 $ 16,537 $ 37,140 $ 35,624 $ 42,130 $ 25,764 $ 23,210
Interest and other............. 1,074 868 1,853 2,094 1,508 946 627
-------- -------- -------- -------- -------- -------- --------
Total revenues............ 24,834 17,405 38,993 37,718 43,638 26,710 23,837
-------- -------- -------- -------- -------- -------- --------
Costs and expenses:
Lease operating expenses....... 4,154 3,486 7,536 7,817 8,123 7,562 6,732
Depreciation, depletion and
amortization................. 8,317 7,952 16,727 19,284 16,488 9,832 10,376
General and administrative..... 1,972 2,440 4,575 5,285 4,433 3,495 3,880
Interest....................... 3,846 2,471 6,175 1,925 1,957 313 1,794
Accelerated vesting and
retirement benefits.......... -- -- -- 5,761 -- -- --
Impairment of oil and gas
properties................... -- -- -- 43,500 -- -- --
-------- -------- -------- -------- -------- -------- --------
Total costs and
expenses................ 18,289 16,349 35,013 83,572 31,001 21,202 22,782
-------- -------- -------- -------- -------- -------- --------
Income (loss) from operations.... 6,545 1,056 3,980 (45,854) 12,637 5,508 1,055
Income tax expense (benefit)... 2,226 359 1,353 (15,100) 4,200 50 --
-------- -------- -------- -------- -------- -------- --------
Net income (loss)................ 4,319 697 2,627 (30,754) 8,437 5,458 1,055
Preferred stock dividends........ 1,105 1,386 2,497 2,779 2,795 2,795 256
-------- -------- -------- -------- -------- -------- --------
Net income (loss) available to
common shares.................. $ 3,214 $ (689) $ 130 $(33,533) $ 5,642 $ 2,663 $ 799
======== ======== ======== ======== ======== ======== ========
Net income (loss) per common
share:
Basic.......................... $ .26 $ (.08) $ .01 $ (4.17) $ .91 $ .46 $ .14
Diluted........................ $ .26 $ (.08) $ .01 $ (4.17) $ .88 $ .45 $ .14
Shares used in computing net
income (loss) per common share:
Basic.......................... 12,163 8,462 8,976 8,034 6,194 5,835 5,755
Diluted........................ 12,398 8,462 9,075 8,034 6,422 5,952 5,755
STATEMENT OF CASH FLOWS DATA:
Cash provided by operating
activities..................... $ 8,950 $ 9,322 $ 21,197 $ 29,721 $ 27,337 $ 14,323 $ 9,452
Cash used in investing
activities..................... (55,318) (26,366) (51,709) (53,592) (81,549) (36,063) (24,237)
Cash provided by financing
activities..................... 21,027 18,078 58,883 14,590 62,140 25,144 11,765
BALANCE SHEET DATA (END OF PERIOD):
Working capital (excluding
current maturities of debt).... $ 3,267 $ 2,368 $ 20,493 $ 1,142 $ 12,719 $ 4,878 $ 4,712
Oil and gas properties, net...... 237,142 173,567 194,365 141,905 150,494 82,489 57,765
Total assets..................... 283,397 211,826 259,877 181,652 190,421 118,520 83,867
Total debt....................... 122,250 101,013 100,250 81,250 60,250 24,250 100
Stockholders' equity............. 127,985 82,400 124,380 84,484 113,701 77,864 75,129
OTHER FINANCIAL DATA:
Capital expenditures, net........ $ 51,253 $ 39,453 $ 68,865 $ 54,196 $ 85,159 $ 36,063 $ 24,237
EBITDA........................... $ 19,643 $ 12,154 $ 28,369 $ 27,564 $ 33,209 $ 16,138 $ 13,582
Cash interest paid............... $ 5,110 $ 3,815 $ 9,013 $ 6,229 $ 4,167 $ 251 $ 1,910
Ratio of EBITDA to cash interest
paid........................... 3.5x 3.4x 3.1x 4.4x 8.0x 64.3x 7.1x
Ratio of earnings to fixed
charges........................ 1.8x -- 1.1x -- 3.3x 8.8x 1.6x
Ratio of total debt to EBITDA.... 3.4x 4.3x 3.5x 2.9x 1.8x 1.5x --
</TABLE>
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<PAGE> 21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Our results of operations are primarily influenced by the prices we receive
for oil and gas production and the costs we incur to produce oil and gas. The
following table shows information about our prices and costs as well as
production volumes. Production for the six months ended June 30, 2000 includes
1,154 MMcf and production for the year ended December 31, 1999 includes 1,300
MMcf, in both cases at an average price of $2.08 per Mcf, associated with a
volumetric production payment. Prices shown below include the effects of our
hedging activities.
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
----------------- ---------------------------
2000 1999 1999 1998 1997
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (MBbls).................................. 130 176 330 310 462
Gas (MMcf)................................... 7,005 6,843 14,606 14,036 13,114
Total production (MMcfe)..................... 7,788 7,898 16,589 15,894 15,887
AVERAGE SALES PRICE:
Oil (per Bbl)................................ $26.58 $11.96 $ 12.16 $ 12.41 $ 18.63
Gas (per Mcf)................................ 2.90 2.11 2.27 2.26 2.56
Total production (per Mcfe).................. 3.05 2.09 2.24 2.24 2.65
AVERAGE COSTS (PER MCFE):
Lease operating expenses (excluding severance
taxes).................................... $ .47 $ .38 $ .39 $ .44 $ .42
Severance taxes.............................. .06 .06 .07 .06 .09
Depreciation, depletion and amortization..... 1.05 1.01 .99 1.19 1.02
General and administrative (net of management
fees)..................................... .25 .31 .28 .33 .28
</TABLE>
Since 1996, we have completed several acquisitions that have significantly
affected our results of operations. Through a series of four transactions, we
acquired 52.5 Bcf of estimated net proved reserves in the Mobile Block 864 area
for a total cost of $48.7 million. In June 1999, in exchange for a volumetric
production payment valued at $14.8 million, 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.
In December 1999, we purchased from Santos USA Corporation an additional
20% working interest in the Boomslang deep water discovery on Ewing Bank 994 for
$7.3 million. This brought our total working interest in the well to 55%.
In April 1998, we sold our Black Bay Complex properties, located in
Louisiana state waters, for $9.4 million. We used these proceeds to repay
amounts outstanding under our bank credit facility.
Inflation has not had a material impact on our results of operations and we
do not expect it 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, 2000 and
1999
Oil and gas revenues for the six months ended June 30, 2000 increased by
$7.3 million, or 44%, to $23.8 million when compared to $16.5 million for the
same period in 1999. For the six-month period ending June 30, 2000, natural gas
production was 7.0 Bcf and natural gas revenues were $20.3 million, increasing
from production of 6.8 Bcf and gas revenues of $14.4 million in the first six
months of 1999. Our average sales price for natural gas in the first six months
of 2000 was $2.90 per Mcf, a $.79 per Mcf increase over the same period in 1999.
When compared to the same period last year, our gas production
S-21
<PAGE> 22
increased by 2% as a result of new production at East Cameron 275, South Marsh
Island 261, High Island A-494 and Vermilion 130 which was offset by production
declines in some of our older producing properties and the depletion of Main
Pass 31. The production declines were expected and considered normal.
For the six months ending June 30, 2000, oil production was 130,400 Bbls
and oil revenues were $3.5 million. During the same period in 1999, oil
production was 176,000 Bbls and revenues totaled $2.1 million. Our increase in
oil revenues resulted from higher oil prices during the first six months of 2000
which averaged $26.58, compared with $11.96 for the same period in 1999.
The following table summarizes oil and gas production from our major
producing properties for the comparable periods.
<TABLE>
<CAPTION>
OIL PRODUCTION (BBLS) GAS PRODUCTION (MCF)
--------------------- ---------------------
SIX MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
--------------------- ---------------------
2000 1999 2000 1999
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Mobile Block 864 Area............................... -- -- 2,815,000 2,553,000
Chandeleur Block 40................................. -- -- 194,000 509,000
Main Pass 163 Area.................................. -- -- 606,000 727,000
North Dauphin Island................................ -- -- 159,000 263,000
Eugene Island 335................................... 11,000 14,000 457,000 505,000
Vermilion 130....................................... -- -- 290,000 --
Main Pass 26........................................ 9,000 35,000 190,000 578,000
Main Pass 31........................................ -- 27,000 -- 907,000
Main Pass 164/165................................... -- -- 112,000 332,000
High Island Block A-494............................. -- -- 449,000 --
Escambia Minerals................................... 57,000 71,000 106,000 127,000
East Cameron 275.................................... 11,000 -- 640,000 --
South Marsh Island 261.............................. -- -- 423,000 --
Other properties.................................... 42,000 29,000 565,000 342,000
------- ------- --------- ---------
Total..................................... 130,000 176,000 7,005,000 6,843,000
======= ======= ========= =========
</TABLE>
Lease operating expenses, including severance taxes, for the first half of
2000 increased 20% to $4.1 million from $3.5 million for the 1999 period. This
increase was primarily the result of increased costs associated with new
production.
Depreciation, depletion and amortization for the first six months of 2000
was $8.3 million. For the same period in 1999, depreciation, depletion and
amortization was $8.0 million. This increase was primarily a result of an
increase in the depletion rate.
General and administrative expenses during the first six months of 2000
decreased to $2.0 million compared with $2.4 million for the six-month period in
1999. The decrease was primarily associated with personnel reductions in 1999.
Interest expense during the first half of 2000 was $3.8 million, increasing
from $2.5 million for the first half of 1999, resulting from an increase in
long-term debt under our bank credit facility and the sale of our $40 million
10.25% senior subordinated notes in July 1999.
We provide for income taxes at the expected statutory rate of 34% of net
income.
Preferred stock dividends were $1.1 million for the first half of 2000 as
compared to $1.4 million for the first half of 1999 due to a decrease in shares
outstanding in 2000 compared to the same period in 1999.
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<PAGE> 23
Comparison of Results of Operations for the Years Ended December 31, 1999 and
1998
Our oil and gas revenues for 1999 were $37.1 million, a 4% increase from
$35.6 million in 1998. Similarly, our production increased 4% from 15,900 MMcfe
in 1998 to 16,600 MMcfe in 1999.
Oil revenues increased from $3.8 million in 1998 to $4.0 million in 1999.
This increase was caused by increased oil production, which increased from 310.0
MBbls in 1998 to 330.0 MBbls in 1999, even though we had a decline in average
sales prices from $12.41 in 1998 to $12.16 in 1999. This production increase was
primarily attributed to Main Pass 26 and Eugene Island 335, which offset the
loss of production from the sale of the Black Bay Complex.
Our gas revenues for 1999 were $33.1 million compared to 1998 revenues of
$31.8 million. Gas production in 1999 increased to 14.6 Bcf from 1998 production
of 14.0 Bcf. The increase in production was attributable to new production from
exploration successes in 1999. Average prices increased from $2.26 per Mcf in
1998 to $2.27 in 1999.
Our lease operating expenses, including severance taxes, decreased from
$7.8 million in 1998 to $7.5 million in 1999. This decrease was attributable to
reduced operating expenses.
Depreciation, depletion and amortization decreased from $19.3 million in
1998 to $16.7 million in 1999. The decrease was primarily due to increased
proved reserves in 1999.
Our general and administrative expenses for 1999 were $4.6 million, or $.28
per Mcfe, compared to $5.3 million, or $.33 per Mcfe, in 1998. This 13% decrease
was primarily the result of personnel reductions which occurred in 1999.
Interest expense was $6.2 million for 1999 and $1.9 million for 1998. This
increase is the result of an increase in debt under our bank credit facility and
the sale of our $40 million 10.25% senior subordinated notes in July 1999.
We provide for income taxes at the expected statutory rate of 34% of net
income.
Comparison of Results of Operations for the Years Ended December 31, 1998 and
1997
Our oil and gas revenues for 1998 were $35.6 million, a 15% reduction from
$42.1 million in 1997. On a Mcfe basis, our 1998 production was the same as that
reported for 1997. The reduction in our revenues was primarily attributable to a
15% reduction in our average sales price per Mcfe.
Oil revenues declined from $8.6 million to $3.8 million. This decline was
caused in part by reduced oil production, which declined from 462.0 MBbls in
1997 to 310.0 MBbls in 1998 and a decline in our average sales prices 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.
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 new production from exploration successes in 1998. The increases in
production were more than offset by a reduction in our average prices from $2.56
per Mcf in 1997 to $2.26 per Mcf in 1998.
Our lease operating expenses, including severance taxes, decreased from
$8.1 million in 1997 to $7.8 million in 1998. This decrease was attributable to
reduced severance taxes which declined from $1.4 million in 1997 to $.9 million
in 1998 because more of our production was from federal waters where we do not
incur severance taxes. Other 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 were partially offset by a
reduction in costs due to the sale of the Black Bay Complex.
Depreciation, depletion and amortization increased as a higher rate was
applied to a relatively constant production volume. Total charges increased from
$16.5 million in 1997 to $19.3 million in 1998.
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<PAGE> 24
The increase in the noncash charge reflects the increase in investment in
evaluated oil and gas properties during 1998.
Our general and administrative expenses for 1998 were $5.3 million, or $.33
per Mcfe, compared to $4.4 million, or $.28 per Mcfe, in 1997. This 19% increase
was primarily the result of the loss of Black Bay management fees, which
previously reduced general and administrative expenses, and slightly higher
corporate expenses.
Interest expense was $1.9 million for 1998 and $2.0 million for 1997.
In December 1998, we recorded a charge of $5.8 million attributable to the
accelerated vesting of the remaining unvested performance shares previously
granted under our stock option plans and of retirement benefits.
Under the full-cost method of accounting, the net capitalized costs of
proved oil and gas properties are subject to a "ceiling test," which limits such
costs to the discounted present value, net of related tax effects, of proved
reserves. If capitalized costs exceed this limit, the excess is charged to
expense. During the fourth quarter of 1998, we recorded a noncash impairment
provision related to oil and gas properties in the amount of $43.5 million
($28.7 million after-tax) primarily due to the significant decline in oil and
gas prices.
Our 1998 results included a deferred income tax benefit of $15.1 million
primarily due to the $14.8 million deferred income tax benefit related to
impairment of oil and gas properties recorded in 1998. We expect to realize this
benefit for tax purposes in future years by utilizing our net operating loss and
statutory depletion carryforwards. We have evaluated the potential realization
of the deferred income tax benefit recorded above in light of our reserve
quantity estimates, our long-term outlook for oil and gas prices and our
expected level of other future expenses. We believe it is more likely than not,
based upon this evaluation, that we will realize the recorded deferred income
tax asset. However, we cannot assure you that such asset will ultimately be
realized.
LIQUIDITY AND CAPITAL RESOURCES
Capital Sources
Our primary sources of capital are cash flows from operations, borrowings
under our bank credit facility, and sales of debt and equity securities. Cash
flow from operations before working capital charges for the first half of 2000
totaled $13.4 million and for the first half of 1999 totaled $9.4 million.
During the first six months of 2000, borrowings under our credit facility
increased by $22.0 million.
Bank credit facility. Borrowings under our 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 extending reserves, as determined by the bank. The credit
facility currently provides for a $30 million borrowing base. At August 31,
2000, the amount available to be borrowed under our credit facility was
approximately $4 million. 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.
On September 5, 2000, we executed a commitment letter with a new lender to
provide a $75 million credit facility with an initial borrowing base of $50
million. The new credit facility will contain terms and conditions similar to
our existing credit facility and will mature on October 31, 2001. The new credit
facility is subject to the successful syndication of the lending group. We
intend to pay all amounts outstanding under our existing credit facility with
borrowings under the new credit facility. See "Description of Bank Credit
Facility and Other Indebtedness -- Bank Credit Facility" for more information
about the existing credit facility.
Material sales of debt and equity securities. In November 1999, we sold
3,680,000 shares of our common stock to the public for total net proceeds of
$41.1 million. We used all of the proceeds to finance portions of our 1999 and
2000 capital expenditure budgets. In July 1999, we issued $40.0 million of
S-24
<PAGE> 25
10.25% senior subordinated notes due 2004, and in July 1997, we issued $36.0
million of 10.125% senior subordinated notes due 2002. We used the proceeds of
the note offerings to repay outstanding amounts under our 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
and the balance to fund a portion of our 1998 capital expenditures.
Capital Expenditures
Our capital expenditures for exploration and development costs related to
oil and gas properties were approximately $51.2 million for the first six months
of 2000. We spent approximately $22.5 million in the Gulf of Mexico shelf area
primarily in the development of the 1999 discoveries at South Marsh Island 261
and East Cameron 275. Expenditures in the Gulf of Mexico shelf area included
exploration costs of approximately $7.3 million related to three unsuccessful
prospects evaluated during the first six months of 2000. The Gulf of Mexico deep
water area expenditures accounted for the remainder of the total capital
expended, with two unsuccessful exploration projects totaling $7.1 million and
the balance for additional delineation drilling at our Medusa discovery and the
drilling of a test well at the Entrada prospect in the first half of 2000.
Interest and general administrative costs allocable directly to exploration and
development projects were approximately $5.0 million for the first six months of
2000.
For the remainder of the year, we will continue evaluating property
acquisitions and drilling opportunities. We have budgeted up to $26 million in
capital expenditures for the remainder of 2000. The major portion of the capital
expenditure budget will be used to drill development and exploratory wells to
increase total proved reserves and production. Our current estimates are that
the budget for the remainder of 2000 can be financed with available cash,
projected cash flow from operations and our credit facility.
Financial Instruments
We periodically use derivative financial instruments to hedge oil and gas
price risks. In a typical hedge transaction, we 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 must pay the
counterparties the difference multiplied by the quantity hedged. We must 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 our production at times when the floating price
exceeds the fixed price, we could be required to make payments under the hedge
agreements even though these 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 September 1, 2000, we had hedged approximately 250 MMcf per month
through October 31, 2000, representing 17% of our estimated gas production
during this period, pursuant to price collars, with an average NYMEX floor price
of $2.50 per MMBtu and an average ceiling price of $2.74 per MMBtu. We had no
other hedge contracts as of September 1, 2000.
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<PAGE> 26
Preferred Stock
As of October 20, 2000, we had 633,361 shares of series A preferred stock
outstanding, which are convertible into our common stock at a conversion price
of $11.00 per share. We may redeem the series A preferred stock for 105% 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 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.
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> 27
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. Our senior
management has worked together for over 20 years. In addition, we have 12
engineering and geoscience professionals with an average of 12 years of
experience with us. We have historically grown our reserves and production by
focusing primarily on low to moderate risk exploration and acquisition
opportunities in the Gulf of Mexico shelf area. Over the last several years, we
have expanded our 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 three additional deep water discoveries on our
Habanero, Medusa and Entrada prospects.
The following table provides information about our estimated net proved
reserves in these areas as of December 31, 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>
GULF OF MEXICO SHELF:
Mobile Block 864 Area....... Callon 48,897 -- 48,897 $ 55,545 18.7%
South Marsh Island 261...... Callon 10,768 32 10,962 16,070 5.4
East Cameron 275............ Callon 5,325 27 5,485 4,865 1.6
Main Pass 26/SL 15827....... Callon 3,024 123 3,761 5,775 2.0
High Island Block A-494
Snapper.................. PetroQuest 2,828 -- 2,828 3,217 1.1
Eugene Island Block 335..... Murphy 1,574 48 1,862 3,212 1.1
Other....................... Various 3,114 69 3,527 1,282 .4
------- ------ ------- -------- -----
Total Shelf......... 75,530 299 77,322 89,966 30.3
------- ------ ------- -------- -----
GULF OF MEXICO DEEP WATER:
Ewing Bank Block 994
Boomslang................ Murphy 13,015 7,230 56,395 53,507 18.1
Mississippi Canyon 538/582
Medusa................... Murphy 8,764 8,835 61,774 65,302 22.0
Garden Banks Block 341
Habanero................. Shell 12,547 6,393 50,902 66,993 22.6
------- ------ ------- -------- -----
Total Deep Water.... 34,326 22,458 169,071 185,802 62.7
------- ------ ------- -------- -----
ONSHORE:
Big Escambia Creek.......... Exxon 1,703 657 5,647 7,785 2.6
Other....................... Various 4,876 420 7,401 12,960 4.4
------- ------ ------- -------- -----
Total Onshore....... 6,579 1,077 13,048 20,745 7.0
------- ------ ------- -------- -----
Total............... 116,435 23,834 259,441 $296,513 100.0%
======= ====== ======= ======== =====
</TABLE>
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<PAGE> 28
GULF OF MEXICO SHELF PROPERTIES
We explore for oil and gas deposits in the Gulf of Mexico shelf area using
the latest in 3-D seismic technology. Since 1996, we have drilled 25 gross (15.6
net) exploration wells in this area, of which 12 gross (9.3 net) were
productive. We also drilled five gross (2.9 net) development wells, all of which
were successful. We currently have an inventory of 12 exploration prospects in
this area, four of which we expect to drill in 2000. In addition to these
prospects, in August 2000 we were the apparent high bidder on six blocks in the
Gulf of Mexico shelf area. Two of these blocks have been awarded and four are
subject to approval by the Minerals Management Service.
We own 278,000 gross (159,000 net) acres in 50 federal blocks and various
state leases in the shelf area, and have a weighted average working interest of
84.6% in 40 producing wells which during the first half of 2000 had average net
daily production of 36.9 MMcfe. Since 1996, we have acquired over 450 square
miles of 3-D seismic data in this area.
The following is a description of the current areas in which we have
activities in the Gulf of Mexico shelf.
Mobile Block 864 Area. The Mobile Block 864 area is located offshore
Alabama in federal waters. During 1997, we acquired four 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 attributable to this area at December 31, 1999, were 48.9
Bcf with a discounted present value of $55.5 million. Net average daily
production during the first half of 2000 was 15.5 MMcf.
South Marsh Island Block 261. In November 1999, we announced a
discovery on this block which encountered 110 feet of net natural gas pay.
We began drilling a second test well in December 1999 and encountered 100
feet of net natural gas pay in five pay sands before it blew out. We
brought the well under control, plugged it and drilled a replacement well
in the first quarter of 2000. Our insurance policy covered the costs
associated with the blowout, the plugging of the well and the drilling of
the replacement well. These two wells are currently producing approximately
19.7 MMcfe per day. We drilled a fourth well in the second quarter of 2000
and encountered 165 net feet of pay in four pay sands. The fourth well is
not scheduled to commence production until the first half of 2001. We own a
100% working interest in these wells. Estimated net proved reserves
attributable to this block as of December 31, 1999 were 11.0 Bcfe with a
discounted present value of $16.1 million.
East Cameron Block 275. In December 1999, we announced a discovery
which encountered net natural gas pay of 160 feet in five intervals between
5,800 feet and 10,500 feet. The well commenced production in April 2000 and
is currently producing approximately 5.2 MMcfe per day. We own a 100%
working interest in this well. Estimated net proved reserves attributable
to this well at December 31, 1999 were 5.5 Bcfe with a discounted present
value of $4.9 million.
Main Pass Block 26/SL 15827. We negotiated a farm-in agreement in 1998
for a 97.0% working interest after identifying a prospect on Main Pass
Block 26 Block based upon a seismic survey we completed in 1996. In August
1998, we drilled the SL 15827 well to a depth of 10,450 feet. This well was
producing during the first half of 2000 at a net average daily rate of 1.1
MMcf and 52 Bbls of oil. Estimated net proved reserves attributable to this
well as of December 31, 1999 were 3.8 Bcfe with a discounted present value
of $5.8 million. We operate this well.
High Island Block A-494 Snapper. In January 1999, we announced a
discovery on our Snapper prospect, which we drilled to a total depth of
8,800 feet. We own a 50.0% working interest in this
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<PAGE> 29
well, which is operated by PetroQuest Energy. The well began production in
July 1999, and averaged 2.5 MMcf per day for the first half of 2000.
Estimated net proved reserves attributable to this well at December 31,
1999 were 2.8 Bcfe with a discounted present value of $3.2 million.
Eugene Island Block 335. In 1997, we drilled three wells on Eugene
Island Block 335, which we acquired in an Outer Continental Shelf lease
sale. We own a 20.0% working interest in the wells, and Murphy operates the
wells. During the first half of 2000, the three wells produced at a net
average daily rate of 2.9 MMcfe. Estimated net proved reserves attributable
to these wells at December 31, 1999 were 1.9 Bcfe with a discounted present
value of $3.2 million.
GULF OF MEXICO DEEP WATER PROPERTIES
We allocate a portion of our capital expenditure budget to the exploration
of deep water areas 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, BP Amoco and Murphy, as operators. Since 1998, we have drilled six gross
(.8 net) exploration wells in our deep water area, of which four gross (.5 net)
were successful. We have also drilled one gross (.2 net) development well which
was successful. We currently have in progress one gross (.1 net) exploratory
well and one gross (.2 net) development well. In September 1998, we announced
our first deep water discovery on our Boomslang prospect, and in February 1999,
we announced a deep water discovery on our Habanero prospect. In September 1999,
we announced a deep water discovery on our Medusa prospect. These discoveries
represent the largest discoveries in our history and have added estimated net
proved reserves of 148.6 Bcfe at December 31, 1999. In April 2000, we announced
a deep water discovery on our Entrada prospect. We currently have an inventory
of 23 deep water exploration prospects, five of which we expect to drill before
year-end 2000.
We own approximately 196,000 gross (34,000 net) acres in 34 blocks in the
deep water areas of the Gulf of Mexico. The following is a description of the
three deep water discoveries which we drilled in 1998 and 1999.
Ewing Bank Block 994 Boomslang. In September 1998, we announced a
discovery on our Boomslang prospect which we acquired in an Outer
Continental Shelf lease sale. We drilled this well in 900 feet of water to
a total depth of 13,200 feet. In December 1999, we acquired an additional
20% working interest, bringing our total working interest in this well to
55%. Murphy operates this well. Our estimated net proved reserves
attributable to the prospect at December 31, 1999 were 56.4 Bcfe with a
discounted present value of $53.5 million. We plan to drill a delineation
well to extend this discovery before the end of 2001. Prior to designing
production facilities for Boomslang, we plan to drill the Sidewinder
prospect. See "Exploration and Development Activities -- Gulf of Mexico
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 interests we held on three adjacent blocks. 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 Shell operates. Estimated net proved
reserves attributable to this well at December 31, 1999 were 50.9 Bcfe with
a discounted present value of $67.0 million. Prior to designing production
facilities for Habanero, we plan to drill the Moccasin and Deep Moccasin
prospects. See "Exploration and Development Activities -- Gulf of Mexico
Deep Water Area" for a description of these prospects.
Mississippi Canyon Blocks 538/582 Medusa. Medusa was our third deep
water discovery and was announced in September 1999. We drilled the initial
test well to a total depth of 16,241 feet and encountered over 120 feet of
pay in two intervals. We performed subsequent sidetrack drilling from the
well bore to determine the extent of the discovery. We drilled a second
successful well in the first quarter of 2000 to further delineate the
extent of the pay intervals. We own a 15% working interest,
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<PAGE> 30
Murphy, the operator, owns a 60% interest and AGIP owns the remaining 25%.
Estimated net proved reserves attributable to this prospect at December 31,
1999 were 61.8 Bcfe with a discounted present value of $65.3 million. We
are currently designing production facilities for the Medusa discovery.
OTHER AREAS
We own various small royalty and working interests in several onshore
areas, which as of December 31, 1999 had total net proved reserves of 13.0 Bcfe
with a discounted present value of $20.7 million. Over 50% of these reserves and
their related discounted present value were attributable to our interest in the
Big Escambia Creek gas field located in south Alabama which Exxon operates.
EXPLORATION AND DEVELOPMENT ACTIVITIES
The following is a summary of our drilling plans through the first half of
2001. We continually review our drilling plans in light of changing
circumstances. Factors that may cause us to change our drilling plans are
described under "Risk Factors."
Gulf of Mexico Shelf Area
West Cameron Block 276. This prospect is in 85 feet of water and we have
scheduled the drilling of the initial well in the fourth quarter of 2000 to
9,500 feet. We estimate that the cost to drill the well will be $1.8 million
($.4 million net to us). If the well is successful, we estimate that two
additional wells will be necessary to drain the reservoir effectively. We own a
25% working interest and Santos USA, the operator, owns a 75% working interest.
West Cameron Block 272. This prospect is in 80 feet of water and the
initial well is scheduled to drill in the fourth quarter of 2000 to 9,000 feet.
We estimate that the cost to drill the well will be $1.9 million ($.4 million
net to us). We own a 20% working interest and Santos USA, the operator, owns an
80% working interest.
West Delta Block 119. This prospect is in 269 feet of water and we have
scheduled the drilling of the test well in the fourth quarter of 2000 to 12,000
feet. This well will offset Ocean Energy's well on the adjacent block, West
Delta Block 68, which logged 193 feet of net pay. We estimate that the cost to
drill the well will be $3.2 million ($2.1 million net to us). We own a 66.7%
working interest and will be the operator. Ocean Energy owns the remaining 33.3%
interest.
East Cameron Block 374. We acquired this prospect, which is in 410 feet of
water, in the March 2000 Outer Continental Shelf Lease Sale. The test well,
which we have scheduled to drill in the fourth quarter of 2000, is adjacent to
East Cameron Block 373 on which Kerr-McGee has three producing wells. We
estimate that the cost to drill the well will be $2.0 million ($.5 million net
to us). We own a 25% working interest and Murphy, the operator, owns the
remaining 75% interest.
Gulf of Mexico Deep Water Area
Entrada -- Garden Banks Blocks 782/785/826/827. In December 1999, we
entered into an agreement with Vastar, now BP Amoco, to pay $3.2 million for a
20% working interest in Garden Banks Blocks 782, 826, 827 and 785. Two prospects
had been identified on the blocks, Entrada and Cirrus. We announced our fourth
deep water discovery, Entrada, in April 2000. The initial exploratory well
encountered over 360 feet of pay in four intervals. The well is located in 4,462
feet of water and we drilled it to a true vertical depth of 15,717 feet. We
performed subsequent sidetrack drilling from the well bore to determine the
extent of the discovery. We drilled a second well in the third quarter of 2000
and we are currently evaluating this well. BP Amoco is the operator and owns the
remaining 80% working interest. The Cirrus prospect, located on Garden Banks
Block 785, is not scheduled to be drilled until the summer of 2001.
Cumberland -- Green Canyon Block 297. We began drilling the initial test
well, which is in 3,225 feet of water, in August 2000. This well will be drilled
to a depth of 16,750 feet and is expected to
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<PAGE> 31
reach total depth in October 2000. We estimate the cost to drill the well will
be $17.5 million ($1.9 million net to us). If the well is successful, production
will be handled by the Allegheny production facility, which is located two miles
from the prospect and operated by AGIP. We own a 7.5% working interest and AGIP
is the operator with a 55% working interest. Murphy owns the balance.
Stonemaker -- Mississippi Canyon Block 493. This prospect is located
northwest and adjacent to the Medusa discovery (Mississippi Canyon Blocks
538/582) in 1,800 feet of water. We plan to drill the test well late in the
fourth quarter of 2000 to 13,000 feet. We estimate that the cost to drill the
well will be $15.0 million ($3.0 million net to us). If the well is successful,
we anticipate a subsea completion with a tie back to planned production
facilities for Medusa. We own a 20% working interest and the operator, Murphy,
owns the remaining 80% interest.
Sidewinder -- Ewing Banks Block 995, Green Canyon Blocks 24/25. This
prospect is adjacent to the Boomslang discovery (Ewing Banks Block 994) in 1,200
feet of water. We plan to drill the test well late in the fourth quarter of 2000
or early 2001 to 16,000 feet. We estimate that drilling costs for the test well
will be $20 million ($3.0 million net to us). If the well is successful, future
production facilities will be shared with Boomslang. We own a 15% working
interest, Samedan Oil Corporation owns a 42.5% working interest and Murphy, the
operator, owns a 42.5% working interest.
Moccasin and Deep Moccasin -- Garden Banks Blocks 253/297/298. These two
prospects are in 1,825 feet of water and are located in the Auger Basin adjacent
to our Habanero discovery (Garden Banks 341). We plan to drill the test well in
the fourth quarter of 2000 to 22,100 feet to test both deep and shallow targets.
We estimate that drilling costs will be approximately $26.0 million ($3.3
million net to us). If the well is successful, future production facilities will
be shared with Habanero. We own a 12.5% working interest, Murphy owns a 37.5%
working interest and Shell, the operator, owns a 50% working interest.
South Moccasin -- Garden Banks Block 297. This prospect, in 1,800 feet of
water, is located in the Auger Basin area adjacent to our Habanero discovery
(Garden Banks Block 341) and the Moccasin and Deep Moccasin prospects. Pending
the results of the Moccasin prospects, we have scheduled the drilling of the
initial well in the first quarter of 2001 to 20,000 feet. We estimate that
drilling costs will be $16.0 million ($2.0 million net to us). We own a 12.5%
working interest, Murphy owns a 37.5% working interest and Shell, the operator,
owns a 50% working interest.
Outer Continental Shelf Lease Sales
Outer Continental Shelf Lease Sale #175, March 2000. We and our partner,
Murphy, were the high bidder on two Gulf of Mexico tracts, East Cameron Block
374 and Mississippi Block 493. East Cameron Block 374, in which we own a 25%
working interest, is located on the shelf, and Mississippi Canyon Block 493,
Stonemaker, in which we own a 20% working interest, is in the deep water area of
the Gulf of Mexico. Both blocks have been awarded by the Minerals Management
Service.
Outer Continental Shelf Lease Sale #177, August 2000. We were,
participating on our own and with partners, the apparent high bidder on eight
Gulf of Mexico tracts. Of the eight offshore tracts, six are on the shelf and
two are in the deep water area of the Gulf of Mexico. Deep water tracts on which
we were the apparent high bidder include Garden Banks Block 653, bid jointly
with Murphy, and Garden Banks Block 738, bid jointly with Vastar, now BP Amoco.
We participated for a 10% working interest in Garden Banks Block 653 and a 20%
working interest in Garden Banks Block 738. The six blocks on the shelf that
were bid 100% by us include Galveston Blocks 271 and 284, Matagorda Block 710,
North Padre Island Block 913, and Mustang Island Blocks 872 and 873. We have
taken a partner and reduced our working interest to 50% for Galveston Blocks 271
and 284 and Matagorda Block 710. Three blocks have been awarded and the
remaining five are subject to approval by the Minerals Management Service.
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<PAGE> 32
OIL AND GAS RESERVES
The following table sets forth information about our estimated net proved
reserves as of the dates set forth below. Huddleston & Co., Inc., our
independent reserve engineers prepared these estimates.
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Proved developed:
Oil (MBbls)............................................... 1,376 2,079 2,976
Gas (MMcf)................................................ 82,109 76,895 88,010
Proved undeveloped:
Oil (MBbls)............................................... 22,458 4,819 426
Gas (MMcf)................................................ 34,326 11,135 728
Total proved:
Oil (MBbls)............................................... 23,834 6,898 3,402
Gas (MMcf)................................................ 116,435 88,030 88,738
Estimated future net cash flows before income taxes
(000s).................................................... $528,659 $152,552 $209,260
======== ======== ========
Discounted present value (000s)............................. $296,513 $ 99,751 $136,448
======== ======== ========
</TABLE>
Our independent reserve engineers prepared the estimates of the proved
reserves and the future net cash flows (and present value thereof) attributable
to these proved reserves. Reserves were estimated using oil and gas prices and
production and development costs in effect on December 31 of 1997, 1998 and
1999, without escalation.
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, including 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 total proved net oil and gas reserves.
S-32
<PAGE> 33
MANAGEMENT
INFORMATION ABOUT OUR DIRECTORS AND EXECUTIVE OFFICERS
The following is information about our directors and executive officers as
of September 1, 2000.
<TABLE>
<CAPTION>
POSITION
NAME AGE SINCE PRESENT POSITION
---- --- -------- ----------------
<S> <C> <C> <C>
John S. Callon........................ 80 1994 Director; Chairman of the Board
Fred L. Callon........................ 50 1994 Director; President; Chief Executive
Officer
Dennis W. Christian................... 54 1994 Director; Senior Vice President; Chief
Operating Officer
John S. Weatherly..................... 48 1994 Senior Vice President and Chief
Financial Officer
James O. Bassi........................ 46 1997 Vice President; Controller
Thomas E. Schwager.................... 49 1997 Vice President
Kathy G. Tilley....................... 55 1996 Vice President
Stephen F. Woodcock................... 49 1997 Vice President
Robert A. Mayfield.................... 50 2000 Secretary
Rodger W. Smith....................... 51 1999 Treasurer
Leif Dons............................. 51 1999 Director
Robert A. Stanger..................... 60 1995 Director
John C. Wallace....................... 62 1994 Director
B. F. Weatherly....................... 56 1994 Director
Richard O. Wilson..................... 70 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 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 1999, he also held the position of Treasurer. 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 member
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<PAGE> 34
of the American Institute of Certified Public Accountants and the Mississippi
Society of Certified Public Accountants. John S. Weatherly and B. F. Weatherly
are brothers.
James O. Bassi is our Vice President and Controller. Prior to being
appointed to that position in November 1997, he was our Corporate Controller
from June 1997 and prior thereto was our manager of the accounting department of
Callon and Callon Petroleum Operating. Mr. Bassi has been employed by us 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.
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.
Robert A. Mayfield is our Secretary. Prior to being appointed to that
position in February 2000, he served as the manager of tax services and
Securities and Exchange Commission reporting since 1981. Prior to joining us,
Mr. Mayfield was employed by McCormick Oil and Gas Company in Houston, Texas. He
received his B.S. degree in accounting from Louisiana Tech University and is a
member of the American Society of Corporate Secretaries.
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 us
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,
natural gas, and water services and Electric Lightwaves, Inc., Seattle,
Washington, a regional fiber optic telephone company.
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<PAGE> 35
Previously, Mr. Stanger was Vice President of Merrill Lynch & Co. He received
his B.A. degree in economics from Princeton University in 1961. Mr. Stanger is a
member of the New York Society of Security Analysts. Robert A. Stanger &
Company, Inc. is a member of the National Association of Securities Dealers.
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 over fifteen 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. Mr. Wilson has been a director of
Transcoastal Marine Services, Inc. since September 1999. 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 show on this table.
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<PAGE> 36
Unless otherwise indicated, each person named in the following table has
the sole power to vote and dispose of the shares listed next to their name.
Information in the tables and accompanying text has been obtained from filings
made with the SEC or, in the case of our directors and executive officers, has
been provided by such individuals. Unless otherwise indicated, the information
provided below is based on information available to us as of September 1, 2000.
<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.................................. 297,958 2.39% -- --
Fred L. Callon.................................. 708,888 5.63% -- --
Dennis W. Christian............................. 245,600 1.95% -- --
John S. Weatherly............................... 224,241 1.78% -- --
Kathy G. Tilley................................. 159,478 1.28% -- --
Stephen F. Woodcock............................. 74,276 * -- --
NON-EMPLOYEE DIRECTORS:
Leif Dons....................................... 10,000 * -- --
Robert A. Stanger............................... 55,856 * -- --
John C. Wallace................................. 2,019,779 16.26% -- --
B.F. Weatherly.................................. 162,664 1.31% -- --
Richard O. Wilson............................... 84,737 * 1,000 *
ALL DIRECTORS AND EXECUTIVE OFFICERS AS A GROUP
(15 PERSONS).................................... 4,146,878 30.20% 1,000 *
CERTAIN BENEFICIAL OWNERS:
Ganger Rolf ASA................................. 1,839,386 14.87% -- --
Fred. Olsengate 2
0152 Oslo, Norway
Bonheur ASA..................................... 1,839,386 14.87% -- --
Fred. Olsengate 2
0152 Oslo, Norway
State Street Research & Management Company...... 827,400 6.69% -- --
One Financial Center, 30th Floor
Boston, Massachusetts 02111-2690
UBS AG.......................................... 644,512 5.21% -- --
Bahnhofstrasse 45
8021, Zurich, Switzerland
New South Capital Management, Inc. ............. 748,425 6.05% -- --
1000 Ridgeway Loop Rd., Suite 233
Memphis, Tennessee 38120
Scudder Kemper Investments, Inc. ............... 751,500 6.08% -- --
345 Park Avenue
New York, New York 10154
Fleet Boston Corporation........................ 647,082 5.23% -- --
One Federal Street
Boston, Massachusetts 02110
AXA Financial, Inc. ............................ 809,497 6.54% -- --
1290 Avenue of the Americas
New York, New York 10104
</TABLE>
---------------
* Under 1%.
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<PAGE> 37
John S. Callon. The shares beneficially owned by John S. Callon include a
1% general partner interest in 105,000 shares held in a family limited
partnership; 10,000 shares held jointly with his wife; 90,000 shares subject to
options under our 1994 Stock Incentive Plan; and 5,000 shares subject to options
under our 1996 Stock Incentive Plan. The shares beneficially owned by John S.
Callon do not include 53,501 shares owned by John S. Callon's wife over which he
disclaims beneficial ownership.
Fred L. Callon. The shares beneficially owned by Fred L. Callon include
184,378 shares held as custodian for certain minor Callon family members; 71,110
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 141,663 shares subject to options under our 1996 Stock
Incentive Plan. The shares beneficially owned by Fred L. Callon do not include
24,939 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
153,915 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 136,081 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 107,498
shares subject to options under our 1996 Stock Incentive Plan.
Stephen F. Woodcock. The shares beneficially owned by Stephen F. Woodcock
include 67,665 shares subject to options under our 1996 Stock Incentive Plan.
Leif Dons. The shares beneficially owned by Leif Dons include 10,000 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
30,000 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 Ganger Rolf ASA and Bonheur ASA; 25,000
shares subject to options under our 1994 Stock Incentive Plan and 30,000 shares
subject to options under our 1996 Stock Incentive Plan. See "Ganger Rolf ASA and
Bonheur 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 30,000 shares subject to options under
our 1996 Stock Incentive Plan. See "Ganger Rolf ASA and Bonheur ASA" below.
Richard O. Wilson. The shares beneficially owned by Richard O. Wilson
include 27,464 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 30,000 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 481,000 shares
subject to options under our 1994 Stock Incentive Plan exercisable within 60
days; and 878,719 shares subject to options under our 1996 Stock Incentive Plan
exercisable within 60 days.
Ganger Rolf ASA and Bonheur ASA. The following information and the
information in the foregoing table is based upon a Schedule 13D/A, filed with
the SEC on September 12, 2000, by Ganger Rolf ASA,
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<PAGE> 38
Bonheur ASA, AS Quatro and AS Quatroto. On August 28, 2000, Ganger Rolf and
Bonheur, jointly purchased from F.O. Energy an aggregate of 1,839,386 shares of
our common stock. Ganger Rolf and Bonheur are currently registered as the joint
record owner of all of the 1,839,386 shares of common stock formerly owned by
F.O. Energy. F.O. Energy no longer owns any of our common stock. Ganger Rolf is
the owner of 28.81% of the outstanding common stock of F.O. Energy. Bonheur is
the owner of 28.81% of the outstanding capital stock of Ganger Rolf. Quatro is
the owner of 21.3% of the outstanding capital stock of Bonheur, and Quatroto is
the owner of 20.8% of the outstanding capital stock of Bonheur. Quatro and
Quatroto disclaim beneficial ownership of the shares of our common stock owned
by Ganger Rolf and Bonheur. John C. Wallace, one of our directors, is a director
of Ganger Rolf and Bonheur, as well as other companies associated with Ganger
Rolf and Bonheur, and as a result, may be deemed to share the power to vote and
dispose of, and therefore be a beneficial owner of the shares of common stock of
Ganger Rolf and Bonheur. The principal business address and principal executive
officer of Ganger Rolf and Bonheur are located at Fred. Olsengate 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.
UBS AG. The following information and the information in the foregoing
table is based on a Schedule 13G, filed with the SEC on February 10, 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.
New South Capital Management, Inc. The information in the foregoing table
is based upon a Schedule 13G, filed with the SEC on February 14, 2000, by New
South Capital Management, Inc.
Scudder Kemper Investments, Inc. The following information and the
information in the foregoing table is based upon a Schedule 13G, filed with the
SEC on January 28, 2000, by Scudder Kemper Investments, Inc. Scudder Kemper
Investments, Inc. has sole voting power with respect to 447,100 shares of common
stock and shared voting power with sole dispositive power with respect to 14,900
shares of common stock.
Fleet Boston Corporation. The following information and the information in
the foregoing table is based upon a Schedule 13G, filed with the SEC on February
14, 2000, by Fleet Boston Corporation. Fleet Boston Corporation has sole voting
power with respect to 545,082 shares of common stock and sole dispositive power
with respect to all of these shares.
AXA Financial, Inc. The following information and the information in the
foregoing table is based upon a Schedule 13G, filed with the SEC on February 14,
2000, by AXA Financial, Inc. AXA Financial, Inc. has sole voting power with
respect to 600,697 shares of common stock, shared voting power with respect to
162,900 shares of common stock and sole dispositive power with respect to all of
these shares.
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<PAGE> 39
DESCRIPTION OF THE NOTES
We will issue 11% Senior Subordinated Notes due 2005 under an indenture,
dated October 26, 2000 between us and American Stock Transfer & Trust Company,
as trustee, which we have supplemented. The following description of the
particular terms of the notes offered hereby supplements, and to the extent
inconsistent therewith replaces, the description of the general terms and
provisions set forth in the accompanying prospectus. The description is a
summary of selected provisions of the indenture, as supplemented, and the notes.
We have not restated the indenture in its entirety. The form of the indenture,
as supplemented, will be filed with the Securities and Exchange Commission as
part of a current report on form 8-K. You should read the indenture because the
indenture, and not this description, will control your rights as a holder of the
notes. You can find the definitions of some terms used in this description under
the subheading "Certain Definitions." Unless otherwise specifically noted in the
following discussion, references to "Callon," "we" or "us" means Callon
Petroleum Company without its Subsidiaries. References to the indenture mean the
indenture, as supplemented. Capitalized terms used in the summary have the
meanings specified in the indenture.
The notes represent our direct unsecured obligations and rank equally with
all our existing senior subordinated notes. The notes are subordinated to our
Senior Indebtedness as discussed under the subheading "Subordination" and are
structurally subordinated to all liabilities of our Subsidiaries. Assuming we
had issued the notes and applied the proceeds as intended as of June 30, 2000,
we would have had $15.6 million of Senior Indebtedness. As of June 30, 2000, our
Subsidiaries had liabilities on their balance sheets of $29.5 million, excluding
guarantees of Senior Indebtedness. The indenture will permit us to incur
additional Senior Indebtedness subject only to limitations described under the
subheading "Certain Covenants -- Incurrence of Indebtedness." Our Credit
Facility constitutes Senior Indebtedness. All indebtedness under our Credit
Facility is secured by substantially all of our and our Subsidiaries' producing
oil and gas properties.
As of the date of the indenture, all of our Subsidiaries will be
"Restricted Subsidiaries." However, under the circumstances described in the
definition of "Unrestricted Subsidiaries," located under the subheading "Certain
Definitions," we will be permitted to designate certain of our Subsidiaries as
"Unrestricted Subsidiaries." Unrestricted Subsidiaries will not be subject to
many of the restrictive covenants in the indenture.
PRINCIPAL, INTEREST, AND MATURITY OF THE NOTES
We will issue notes with a maximum aggregate principal amount of $36.8
million. The notes will mature on December 15, 2005, unless we elect to redeem
them earlier.
Interest on the notes will accrue at the rate of 11% per annum, and we will
pay interest quarterly on the 15th day of March, June, September and December,
commencing on December 15, 2000. We will make each interest payment to the
holders of record of the notes on the 1st day of March, June, September and
December immediately preceding the interest payment. Interest on the notes will
accrue from the date of original issuance and, thereafter, from the date we most
recently paid interest.
REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND PRINCIPAL
Book-Entry Notes
We will issue the notes in the form of a global note that will be deposited
with The Depository Trust Company, New York, New York ("DTC"). This means that
we will not issue certificates to holders. One global note will be issued to DTC
which will keep an electronic record of its participants whose clients have
purchased the notes. The participant will then keep a record of its clients who
purchased the notes. Unless a global note is exchanged in whole or in part for a
certificated note, a global note may not be transferred; except that DTC, its
nominees, and their successors may transfer a global note as a whole to one
another.
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DTC and its participants will show beneficial interests in and make
transfers of beneficial interests in global notes only through their records.
We, the trustee and the paying agent will not maintain, review or supervise
these records. The laws of some states require that some persons take physical
delivery in definitive form of securities which they own. If these laws apply,
they may limit the ability to transfer beneficial interests in the global note.
DTC will hold the notes through its nominee, Cede & Co. We will wire
principal and interest payments either directly to Cede & Co. or to the trustee
or other paying agent for payment to Cede & Co. We, the trustee and the paying
agent will treat Cede & Co. as the owner of the global notes for all purposes
and will have no direct responsibility if Cede & Co. fails to distribute those
payments to owners of beneficial interest in the global notes.
It is DTC's current practice, upon receipt of any payment of principal or
interest, to credit participants' accounts on the payment date according to
their holdings of beneficial interests in the global notes as shown on DTC's
records. In addition, it is DTC's current practice to assign any consenting or
voting rights to participants whose accounts are credited with notes on a record
date by using an omnibus proxy. Customary practices between participants and
owners of beneficial interests will govern payments by participants to owners of
beneficial interests in the global notes and voting by participants, as is the
case with notes held for the account of customers registered in "street name."
However, those payments will be the responsibility of the participants and not
of DTC, the trustee, the paying agent or us.
We will issue certificated notes in exchange for a global note with the
same terms in authorized denominations only if:
- DTC notifies us that it is unwilling or unable to continue as depositary
and we have not appointed a successor depositary within 90 days; or
- DTC requests an exchange and an event of default has occurred and is
continuing.
Certificated Notes
If we issue certificated notes, they will be registered in the name of the
holder of the note. The notes may be transferred or exchanged, pursuant to
administrative procedures in the indenture, without the payment of any service
charge, other than any tax or other governmental charge, by contacting the
trustee.
Principal of, interest and any premium on certificated notes will be paid
at designated places. Payment may be made by check mailed or by wire transfer to
the persons in whose names the notes are registered on the days specified in the
indenture.
About DTC
DTC has provided us the following information:
DTC is a limited-purpose trust company organized under the New York Banking
Law, a "banking organization" within the meaning of the New York Banking law, a
member of the United States Federal Reserve System, a "clearing corporation"
within the meaning of the New York Uniform Commercial Code and a "clearing
agency" registered under the provisions of Section 17A of the Securities
Exchange Act of 1934. DTC holds securities that its participants deposit with
DTC. DTC also records the settlement among participants of securities
transactions, such as transfers and pledges, in deposited securities through
computerized records for participants' accounts. This eliminates the need to
exchange certificates. Participants include securities brokers and dealers,
banks, trust companies, clearing corporations and certain other organizations.
DTC's book-entry system is also used by other organizations such as
securities brokers and dealers, banks and trust companies that work through a
participant. The rules that apply to DTC and its participants are on file with
the SEC.
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DTC is owned by a number of its participants and by the New York Stock
Exchange, Inc., The American Stock Exchange, Inc. and the National Association
of Securities Dealers, Inc.
SUBORDINATION
The payment of principal, premium, if any, and interest on the notes will
be subordinated to the prior payment in full of all of our Senior Indebtedness.
The holders of Senior Indebtedness will be able to receive payment in full
of all amounts due in respect of Senior Indebtedness, before the holders of
notes will be able to receive any payment with respect to the notes, other than
payments in the form of Permitted Junior Securities, and payments made pursuant
to the terms described under the subheading "Consolidation, Merger and Sale of
Assets," if there is a distribution to our creditors:
- in our liquidation or dissolution;
- in a bankruptcy, reorganization, insolvency, receivership or similar
proceeding relating to us, our creditors or our property;
- in an assignment for the benefit of our creditors; or
- in any marshalling of our assets and liabilities.
We also may not make any payment in respect of the notes, other than
payments of Permitted Junior Securities, if:
- a Payment Event of Default on Specified Senior Indebtedness occurs and is
continuing beyond any applicable grace period; or
- any other default occurs and is continuing on Specified Senior
Indebtedness that permits holders of the Specified Senior Indebtedness to
accelerate its maturity, and we receive or the trustee receives a notice
of this default, which we refer to as a "Payment Blockage Notice," from
the holders of any Specified Senior Indebtedness.
We will resume making payments on the notes and any missed payments:
- in the case of a Payment Event of Default, upon the date that we cure or
obtain the waiver of this default; and
- in case of a Non-payment Event of Default, the earlier of the date that
we cure or obtain the waiver of the Non-payment Event of Default or 179
days after the date on which we receive or the trustee receives the
applicable Payment Blockage Notice, or the date on which the holders that
initiated the Payment Blockage Notice terminate the payment blockage
period, unless the maturity of any Specified Senior Indebtedness has been
accelerated.
No new Payment Blockage Notice may be delivered unless and until 360
consecutive days have elapsed since the effectiveness of the immediately prior
Payment Blockage Notice. No Non-payment Event of Default that existed or was
continuing on the date of delivery of any Payment Blockage Notice to us or the
trustee can be made the basis for a subsequent Payment Blockage Notice.
Any payments that we fail to make on the notes when due or within an
applicable grace period will constitute an Event of Default under the indenture
that entitles holders of the notes to accelerate the maturity of the notes.
If the trustee or any holder of a note receives any payment or property
prohibited by the subordination provisions of the indenture, the payment and
property must be paid over to us or the person making payments to our creditors.
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As a result of the subordination provisions described above, in the event
of our bankruptcy, liquidation or reorganization, holders of the notes may
recover less ratably than our creditors that are holders of Senior Indebtedness.
See "Risk Factors."
The subordination provisions described above will not apply to the notes
upon a legal or covenant defeasance described under the subheading "Legal
Defeasance and Covenant Defeasance."
CERTAIN COVENANTS
Restricted Payments
We will not, and will not permit any of our Restricted Subsidiaries to,
directly or indirectly (we refer to the payments in the following three clauses
as "Restricted Payments"):
- declare or pay any dividend on our or any of our Restricted Subsidiaries'
capital stock (other than dividends or distributions payable to us or any
wholly owned Restricted Subsidiary or payable solely in shares of our or
our Restricted Subsidiaries' capital stock);
- purchase, redeem or retire any of our or our non-wholly owned Restricted
Subsidiaries' capital stock or any warrants, rights or options to
purchase or acquire any shares of such capital stock; or
- make any other payment or distribution in respect of our capital stock.
if, at the time of and after giving effect to the applicable Restricted Payment:
- an Event of Default would have occurred; or
- the Restricted Payment, together with the aggregate amount of all other
Restricted Payments (excluding Permitted Restricted Payments) made by us
and our Restricted Subsidiaries after the date of the indenture, would
exceed the sum of:
(1) 50% of our Consolidated Net Income subsequent to June 30, 2000,
with 100% reduction for a loss; plus
(2) the cumulative net proceeds received by us from the issuance and
sale after the date of the indenture of our capital stock, including in
these net proceeds the face amount of any indebtedness that has been
converted into our common stock after the date of the indenture.
So long as no Event of Default has occurred and is continuing, the
preceding provisions will not prohibit:
- Restricted Payments in an aggregate amount not to exceed $10 million;
- the payment of regular periodic dividends on shares of our series A
preferred stock or any other series of our preferred stock; and
- the repurchase, redemption, other acquisition or retirement of any shares
of any class of our or any of our Restricted Subsidiaries' capital stock
in exchange for, or out of the aggregate net cash proceeds of a
substantially concurrent issuance and sale, other than to a Restricted
Subsidiary, of shares of our common stock.
We refer to all these payments and other actions set forth in the three
clauses above collectively as "Permitted Restricted Payments." Permitted
Restricted Payments will not reduce the amount that would otherwise be available
for Restricted Payments, except in the case of dividends declared or paid on
shares of our preferred stock, other than the series A preferred stock, which
dividends will reduce the amount available under clauses (1) and (2) above. The
amount of any Restricted Payments payable in property will be the fair market
value of such property as determined by our board of directors.
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Incurrence of Indebtedness
We will not, and will not permit any of our Restricted Subsidiaries to,
create, incur, assume, guarantee or become liable (collectively, "incur"), with
respect to any Indebtedness, including Acquired Indebtedness but excluding
Permitted Indebtedness, if, immediately after we incur this debt (including
giving effect to the retirement of any existing Indebtedness from the proceeds
of such additional Indebtedness):
- the ratio of:
(1) the aggregate amount of our and our Restricted Subsidiaries'
outstanding Indebtedness as of the end of our immediately preceding fiscal
quarter, determined on a consolidated basis under GAAP, to
(2) Consolidated EBITDA for our immediately preceding four fiscal
quarters, would exceed 10.0 to 1.0; or
- the ratio of:
(1) Consolidated EBITDA for our immediately preceding four fiscal
quarters, to
(2) Consolidated Interest Expense for our immediately preceding four
fiscal quarters, would be less than 1.1 to 1.0.
We will also not permit any Restricted Subsidiary to incur any
Indebtedness, except to us or another Restricted Subsidiary, that is expressly
subordinate in right of payment to any other Indebtedness of that Restricted
Subsidiary.
Liens
We will not, and will not permit any of our Restricted Subsidiaries to,
directly or indirectly, create, incur, assume or suffer to exist any Lien of any
kind on any asset now owned or hereafter acquired to secure any Pari Passu
Indebtedness or Subordinated Indebtedness, unless,
- the Lien is a Permitted Lien; or
- prior to, or at the same time that we incur a Lien, we directly secure
the notes equally and ratably, provided that:
(1) if the secured indebtedness is Pari Passu Indebtedness, the Lien
securing such Pari Passu Indebtedness is subordinate to, or pari passu
with, the Lien securing the notes; and
(2) if the secured indebtedness is Subordinate Indebtedness, the Lien
securing the Subordinated Indebtedness is subordinate to the Lien securing
the notes at least to the same extent as the Subordinated Indebtedness is
subordinated to the notes.
This covenant does not apply to any Lien securing Acquired Indebtedness,
provided that the Lien extends only to the properties or assets that were
subject to the Lien prior to the acquisition by us or our Restricted Subsidiary
and we did not create, incur or assume any Lien in contemplation of the
acquisition transaction.
Ranking of Future Indebtedness
We will not incur or permit to remain outstanding any Indebtedness,
including Acquired Indebtedness and Permitted Indebtedness, which is expressly
subordinate to any Senior Indebtedness, other than Subordinated Indebtedness or
Pari Passu Indebtedness. The incurrence of any unsecured Senior Indebtedness is
not, because of its unsecured status, deemed to be subordinate in right of
payment to any secured Senior Indebtedness.
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Dividend and Other Payment Restrictions Affecting Subsidiaries
We will not, and will not permit any of our Restricted Subsidiaries to,
directly or indirectly, create or cause any encumbrance or restriction on the
ability of any Restricted Subsidiary to:
- pay dividends in cash or make any other distribution on its capital stock
to us or any other Restricted Subsidiary;
- pay any indebtedness owed to us or any other Restricted Subsidiary;
- make loans, advances or capital contributions to us or any other
Restricted Subsidiary; or
- transfer any of its properties to us or another Restricted Subsidiary.
However, the preceding restrictions will not apply to encumbrances or
restrictions existing under or by reason of:
- an agreement governing Acquired Indebtedness of any acquired Person that
becomes a Restricted Subsidiary, provided, that any restriction or
encumbrance under the agreement existed at the time of acquisition, was
not put in place in anticipation of the acquisition, and is not
applicable to any Person other than the Person or property of the Person
so acquired;
- customary provisions of any of our or our Restricted Subsidiaries' leases
or licenses relating to the property covered that we or a Restricted
Subsidiary entered into in the ordinary course of business;
- applicable law;
- the indenture, the Credit Facility or other indebtedness or other
agreements existing on the date of original issuance of the notes;
- an agreement entered into for the sale or disposition of the stock,
business or properties of a Restricted Subsidiary;
- purchase money obligations, but only to the extent the purchase money
obligations restrict or prohibit the transfer of the property so
acquired;
- customary non-assignment provisions in installment purchase contracts;
- the requirements of a lender or purchaser of any indebtedness of a
Restricted Subsidiary in connection with a financing of the acquisition
of property, including the purchase of asset portfolios and the
underwriting or origination of mortgage loans, by a Restricted Subsidiary
to the extent this restriction applies to the transfer to us or any other
Restricted Subsidiary of the property acquired after the date of the
indenture;
- an agreement that extends, refinances, renews or replaces any agreement
described in the foregoing clauses; and
- Liens containing customary limitations on the transfer of collateral
which are not prohibited as described in the "Liens" covenant and do not
restrict the ability of a Restricted Subsidiary to transfer any of its
property or assets to us or another Restricted Subsidiary.
Transactions with Affiliates
We will not, and will not permit any of our Restricted Subsidiaries to,
enter into any transaction or series of related transactions involving payments
in excess of $50,000, with any of our Affiliates, other than us or a Restricted
Subsidiary, unless our board of directors:
- determines that the transaction is on terms that are no less favorable to
us or the Restricted Subsidiary than would be available at such time in a
comparable transaction in arm's length dealings with an unrelated Person;
and
- the board of directors adopts a resolution evidencing such determination.
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The preceding paragraph will not apply to:
- Restricted Payments that are permitted by the provisions of the indenture
described in the "Restricted Payments" covenant;
- fees and compensation paid to, and indemnity provided on behalf of, our
and our Restricted Subsidiaries' officers, directors, employees or
consultants; or
- payments for goods and services purchased in the ordinary course of
business on an arm's length basis.
Change of Control
Upon the occurrence of a Change of Control, we are obligated to make an
offer to purchase all of the outstanding notes for a purchase price equal to
101% of the principal amount of the notes plus accrued and unpaid interest, if
any, on the notes to the date we purchase the notes. We are required to purchase
all notes tendered and not withdrawn.
In order to effect the Change of Control offer, we must mail to each holder
of the notes a notice of the Change of Control offer no later than 30 days after
the Change of Control occurs. We must consummate the offer on a business day not
less than 30 days nor more than 60 days after the mailing of the notice of the
Change of Control. We are required to keep the offer open for at least 20
business days. The notice governs the terms of the offer and states the
procedures that holders of notes must follow to accept the offer.
We will not be required to make a Change of Control offer upon a Change of
Control if a third party makes a Change of Control offer that meets the
requirements of the indenture, and purchases all notes validly tendered and not
withdrawn under the Change of Control offer.
The definition of Change of Control includes a phrase relating to the sale,
lease, transfer, conveyance or other disposition of "all or substantially all"
of our and our Restricted Subsidiaries' assets taken as a whole. Although there
is a limited body of case law interpreting the phrase "substantially all," there
is no precise established definition of the phrase under applicable law.
Accordingly, the ability of a holder of notes to require us to repurchase their
notes as a result of a sale, lease, transfer, conveyance or other disposition of
less than all of our and our Restricted Subsidiaries' assets taken as a whole
may be uncertain.
We will comply with Rule 14e-1 under the Exchange Act and any other
securities laws and regulations, to the extent these laws or regulations are
applicable, in connection with the repurchase of the notes as a result of a
Change of Control.
REPORTS
As long as we are a reporting company under the Exchange Act, we will
furnish holders of the notes with our annual reports containing audited
consolidated financial statements and our interim reports containing our
quarterly unaudited consolidated summary financial data. If we cease to be a
reporting company, we will furnish holders of the notes with our audited
consolidated financial statements and our quarterly unaudited consolidated
summary financial statements.
EVENTS OF DEFAULT AND REMEDIES
Each of the following is an Event of Default:
- failure to pay any interest on the notes when due for 30 days, whether or
not prohibited by the subordination provisions of the indenture;
- failure to pay the principal of, or premium, if any, on, the notes when
due as provided in the indenture, whether or not prohibited by the
subordination provisions of the indenture;
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- failure to comply with the covenants described under "-- Certain
Covenants -- Change of Control."
- failure to perform, or a breach of, any other covenant set forth in the
indenture for 30 days after receipt of written notice from the trustee or
holders of at lest 25% in aggregate principal amount of the outstanding
notes specifying the default and requiring that we remedy such default;
- failure to pay at Stated Maturity of our or any Restricted Subsidiaries'
Indebtedness having an outstanding principal amount due at Stated
Maturity greater than $2.5 million for a period of 30 days beyond any
applicable grace period;
- an event of default as defined in any mortgage, indenture or instrument
of ours or a Restricted Subsidiary that has resulted in acceleration of
Indebtedness which, together with the principal amount of any other
Indebtedness so accelerated, exceeds $2.5 million at any time, and we do
not cure or obtain the waiver of the default and the acceleration is not
rescinded or annulled within 30 days from the occurrence of the
acceleration;
- certain events of insolvency, receivership or reorganization of us or any
Material Subsidiary; and
- failure by us or any Material Subsidiary to satisfy a final judgment for
the payment of money in excess of $2.5 million for a period of 30 days
without a stay of execution.
If an Event of Default arising from certain events of insolvency,
receivership or reorganization occurs and is continuing, all outstanding notes
will become due and payable immediately without further action or notice. If any
other Event of Default occurs and is continuing,
- the trustee or the holders of at least 25% in aggregate principal amount
of the then outstanding notes may declare all the notes to be due and
payable immediately; and
- the trustee, upon the request of the holders of not less than 25% in
aggregate principal amount of the then outstanding notes, shall declare
all of the notes to be due and payable.
After a declaration of acceleration under the indenture, but before the
trustee obtains a judgment for payment of the money due, the holders of a
majority in aggregate principal amount of the outstanding notes may rescind the
declaration by written notice to us and the trustee, if:
- we have paid or deposited with the trustee a sum sufficient to pay:
(1) all sums paid or advanced by the trustee under the indenture and
the reasonable compensation, expenses, disbursements and advances of the
trustee, its agents and counsel;
(2) all overdue interest on the notes;
(3) the principal of any notes which have become due otherwise than by
the declaration of acceleration and interest at the rate borne by the
notes; and
(4) to the extent that payment of interest is lawful, interest upon
overdue interest and principal at the rate borne by the notes (without
duplication);
- the rescission would not conflict with any judgment of a court of
competent jurisdiction; and
- we have cured or obtained the waiver of all Events of Default, other than
the nonpayment of principal of (or premium, if any, on) or interest on
the notes that has become due solely by the declaration of acceleration.
A holder of a note may institute proceedings for the enforcement of the
payment of the principal, premium, if any, and interest on the note on or after
the respective due dates expressed in the note. No
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holder of any note will have any right to institute any other proceedings with
respect to the indenture, unless:
- the holder has notified the trustee of a continuing Event of Default;
- the holders of at least 25% in aggregate principal amount of the
outstanding notes have made written request and offered reasonable
indemnity to the trustee to institute these proceedings as trustee under
the indenture;
- the trustee has not received directions inconsistent with this written
request by holders of a majority in aggregate principal amount of the
outstanding notes; and
- the trustee has failed to institute these proceedings within 60 days of
receipt of the notice.
If a default or Event of Default occurs and is continuing and is known to
the trustee, the trustee will mail to each holder of notes notice of the default
or Event of Default within 90 days after the occurrence of the default or Event
of Default. The trustee may withhold from holders of the notes notice of any
continuing Event of Default, except an Event of Default relating to the payment
of principal, premium, if any, or interest, if it determines in good faith that
withholding notice is in their interest.
The holders of a majority in aggregate principal amount of the notes then
outstanding may on behalf of the holders of all of the notes waive any existing
Event of Default and its consequences, except a continuing Event of Default in
the payment of principal of, or premium, if any, on, or interest on the notes or
of a provision of the indenture that cannot be modified or amended without the
consent of the holder of each note affected as described below under the
subheading "Modification of Indenture; Waiver of Covenants."
We must deliver to the Trustee annual and quarterly statements regarding
compliance with the indenture. Upon becoming aware of any default or Event of
Default, we must deliver to the trustee a statement specifying such default or
Event of Default.
REDEMPTION AT OPTION OF THE COMPANY
We may redeem the notes, in whole or part, at 100% of their principal
amount plus accrued interest, on or after March 15, 2003 by giving not less than
30 nor more than 60 days' notice to the holders. If we elect to redeem less than
all of the notes, the trustee will select which notes, or portions of notes not
to be less than $1,000, to redeem. On the redemption date, interest will cease
to accrue on the notes or portions of notes called for redemption.
MODIFICATION OF INDENTURE; WAIVER OF COVENANTS
We generally may amend the indenture with the written consent of a majority
in principal amount of the outstanding notes. The holders of a majority in
principal amount of the outstanding notes may also waive our compliance with
some covenants. We must, however, obtain the consent of each holder of notes
affected by an amendment or waiver which does any of the following:
- changes the maturity date of the principal of, or the due date of any
installment of interest on, any note;
- reduces the principal of, or the rate of interest on, any note;
- changes the place of payment or the currency in which any portion of the
principal of (or premium, if any, on), or interest on, any note is
payable;
- impairs the right to institute suit for enforcement of any such payment;
- reduces the percentage of holders of the outstanding notes necessary to
modify the indenture;
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- modifies the foregoing requirements or reduces the percentage of
outstanding notes necessary to waive any past default or some covenants;
or
- reduces the relative ranking of the notes.
CONSOLIDATION, MERGER AND SALE OF ASSETS
The indenture generally permits a consolidation, merger, or sale of all or
substantially all of our assets to another entity, subject to our obligation to
offer to repurchase the notes in the case of a transaction that is a Change of
Control as long as it does not cause a default or an Event of Default. If this
happens, the remaining or acquiring entity:
- if other than us, must be formed in a U.S. jurisdiction and must assume
our obligations under the indenture; and
- we must be able to incur $1.00 of Indebtedness in compliance with the
incurrence of indebtedness covenant in the indenture immediately after
the merger.
LEGAL DEFEASANCE AND COVENANT DEFEASANCE
Legal Defeasance
As long as we take steps to ensure that you will receive all of your
payments under the notes and are able to transfer the notes, we can elect to
legally release ourselves from any obligations on the notes, which we call
"legal defeasance," other than:
- the rights of holders of outstanding notes to receive payment in respect
of the principal of, and premium, if any, and interest on, the notes when
these payments are due;
- our obligation to replace any temporary notes, register the transfer or
exchange of any notes, replace mutilated, destroyed, lost or stolen notes
and maintain an office or agency for payments in respect of the notes;
- the rights, powers, trusts, duties and immunities of the trustee; and
- the legal defeasance provisions of the indenture.
To accomplish legal defeasance, the following must occur:
- We must irrevocably deposit in trust for the benefit of all holders of
notes money and/or U.S. government or U.S. government agency notes or
bonds that will generate enough cash to make interest, principal and any
other payments on the notes on their various due dates.
- There must be a change in current U.S. federal tax law or an IRS ruling
that lets us make that deposit without causing you to be taxed on the
notes any differently than if we did not make the deposit and just repaid
the notes ourselves. Under current U.S. federal tax law, the deposit and
our legal release from the securities would be treated as though we took
back your notes and gave you your share of the cash and notes or bonds
deposited in trust. In that event, you could recognize gain or loss on
the notes you give back to us.
- We must deliver to the trustee a legal opinion confirming the tax law
change described above and that all of the conditions to legal defeasance
in the indenture have been fulfilled.
We will not be able to achieve legal defeasance if there is a continuing
Event of Default under the indenture or if doing so would violate any other
material agreements to which we are a party. If we ever did accomplish legal
defeasance, as described above, you would have to rely solely on the trust
deposit for repayment on the notes. You could not look to us for repayment in
the unlikely event of any shortfall.
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Covenant Defeasance
Under current U.S. federal tax law, we can make the same type of deposit
described above and be released from some covenants relating to the notes. The
release from these covenants is called "covenant defeasance." In that event, you
would lose the protection of these covenants but would gain the protection of
having money and securities set aside in trust to repay the notes. In order to
achieve covenant defeasance, we must do the following:
- deposit in trust for the benefit of all holders of the notes money and/or
U.S. government or U.S. government agency notes or bonds that will
generate enough cash to make interest, principal and any other payments
on the notes on their various due dates.
- deliver to the trustee a legal opinion confirming that under current U.S.
federal tax law we may make that deposit without causing you to be taxed
on the notes any differently than if we did not make the deposit and just
repaid the notes ourselves. The opinion must also state that all of the
conditions to covenant defeasance in the indenture have been fulfilled.
We will not be able to achieve covenant defeasance if there is a continuing
Event of Default under the indenture or if doing so would violate any other
material agreements to which we are a party. The indenture describes the
covenants that we may fail to comply with without causing an Event of Default if
we accomplish covenant defeasance.
If we elect to make a deposit resulting in covenant defeasance, the amount
of money and/or U.S. government obligations deposited in trust should be
sufficient to pay amounts due on the notes at the time of their maturity.
However, if the maturity of the notes is accelerated due to the occurrence of an
Event of Default, the amount in trust may not be sufficient to pay all amounts
due on the notes. We will remain liable for the shortfall as described in the
indenture.
SATISFACTION AND DISCHARGE OF THE INDENTURE
We will have no further obligations under the indenture as to all
outstanding notes, other than surviving rights of registration of transfers of
the notes, when:
- all notes have been delivered to the trustee for cancellation; or all
notes have become due and payable or, within one year, will become due
and payable or be redeemed and we have deposited with the trustee funds
sufficient to pay interest, principal and any other payments on all
outstanding notes on their various due dates;
- we have paid all other sums then due and payable under the indenture by
us; and
- we have delivered to the trustee an officers' certificate and legal
opinion, which, taken together, state that we have complied with all
conditions precedent under the indenture relating to the satisfaction and
discharge of the indenture.
GOVERNING LAW
Legal interpretations of the indenture and notes will be made using the
laws of the State of New York.
CONCERNING THE TRUSTEE
American Stock Transfer & Trust Company will act as trustee under the
indenture. The indenture provides for indemnification of the trustee by us under
some circumstances.
The indenture limits the rights of the trustee to obtain payments of claims
in some cases if it becomes our creditor. While the trustee is permitted to
engage in other transactions, if the trustee acquires any conflicting interests
governed by the Trust Indenture Act of 1939, the trustee must either eliminate
this conflict or resign.
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The trustee is the transfer agent and registrar for our common stock and
series A preferred stock. Also, the trustee is the trustee under our 2001
Indenture, 2002 Indenture and 2004 Indenture.
CERTAIN DEFINITIONS
Set forth below are some of the defined terms used in the indenture. You
should read the indenture for a full disclosure of these terms, as well as any
other capitalized terms used for this description of notes for which we do not
provide a definition.
"Acquired Indebtedness" means Indebtedness of a Person existing at the time
that Person becomes a Restricted Subsidiary or assumed in connection with the
acquisition by us or a Restricted Subsidiary of assets from that Person, and not
incurred in connection with, or in anticipation of, that Person becoming a
Restricted Subsidiary or such acquisition. Acquired Indebtedness will be deemed
to be incurred on the date of the related acquisition of assets from any Person
or the date the acquired Person becomes a Restricted Subsidiary.
"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with the specified Person. For the purposes of this definition,
"control," when used with respect to any specified Person, means the power to
direct the management and policies of the Person, directly or, indirectly,
whether through the ownership of voting securities, by contract or otherwise;
and the terms "controlling" and "controlled" have meanings correlative to the
foregoing.
"Average Life" means, with respect to any Indebtedness, as at any date of
determination the quotient obtained by dividing:
- the sum of the products of:
(1) the number of years (and any parts thereof from the date of
determination to the date or dates of each successive scheduled principal
payment (including, without limitation, any sinking fund or mandatory
redemption payment requirements) of such Indebtedness multiplied by;
(2) the amount of each such principal payment; by
- the sum of all such principal payments.
"Capitalized Lease Obligation" means, as to any Person, the obligations of
that Person to pay rent or other amounts under the lease of (or other agreement
conveying the right to use) real or personal property which obligations are
required to be classified and accounted for as capital lease obligations on a
balance sheet of that Person under GAAP and, for purposes of the indenture, the
amount of those obligations at any date shall be the capital amount thereof at
such date, determined in accordance with GAAP.
"Change of Control" means the occurrence of any of the following:
- the sale, lease, transfer, conveyance or other disposition (other than by
way of merger or consolidation), in one or a series of related
transactions, of all or substantially all of our and our Restricted
Subsidiaries' assets taken as a whole to any "person" (as that term is
used in Section 13(d)(3) of the Securities Exchange Act of 1934);
- the adoption of a plan relating to our liquidation or dissolution;
- the consummation of any transaction, including, without limitation, any
purchase, sale, acquisition, disposition, merger or consolidation, the
result of which is that any "person," as defined above, becomes the
"beneficial owner" (as that term is described in Rule 13d-3 and Rule
13d-5 under the Securities Exchange Act of 1934), directly or indirectly,
of more than 50% of the aggregate voting power of all classes of our
Voting Stock, provided that the sale of our Voting Stock, preferred
stock, or rights to acquire our Voting Stock or preferred stock to an
underwriter in connection with a firm commitment underwriting will not
constitute a Change of Control; or
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- the first day on which a majority of the members of our board of
directors are not Continuing Directors.
"Consolidated EBITDA" means, for any period, determined in accordance with
GAAP on a consolidated basis for us and our Restricted Subsidiaries, the sum of
Consolidated Net Income, plus depreciation, depletion, amortization and other
non-cash charges, income tax expense, and Consolidated Interest Expense, for
that period, each as deducted in determining Consolidated Net Income.
"Consolidated Interest Expense" means, for any period, the interest expense
for that period, which is required to be shown as such on both our and our
Restricted Subsidiaries' financial statements, on a consolidated basis, prepared
in accordance with GAAP.
"Consolidated Net Income" means, for any period, the amount of our and our
Restricted Subsidiaries' consolidated net income (loss) for that period,
determined in accordance with GAAP; provided, however, that there shall be
included in Consolidated Net Income any net extraordinary gains or losses for
that period (less all fees and expenses related thereto); and, provided,
further, that there shall not be included in Consolidated Net Income:
- any net income (loss) of a Restricted Subsidiary for any portion of that
period during which it was not a Consolidated Subsidiary;
- any net income (loss) of businesses, properties or assets acquired or
disposed of (by way of merger, consolidation, purchase, sale or
otherwise) by us or any Restricted Subsidiary for any portion of that
period prior to the acquisition thereof or subsequent to the disposition
thereof; or
- any net income for that period resulting from transfers of assets
received by us or any Restricted Subsidiary from an Unrestricted
Subsidiary.
"Consolidated Subsidiary" means a Restricted Subsidiary the financial
statements of which are consolidated with our financial statements.
"Continuing Directors" means, as of any date of determination, any member
of our board of directors who:
- was a member of our board of directors on the date of the indenture; or
- was nominated for election or elected to our board of directors with the
approval of a majority of the Continuing Directors who were members of
our board at the time of their nomination or election.
"Credit Facility" means the Amended and Restated Credit Agreement, dated as
of October 31, 1996, among us, Callon Petroleum Operating Company, Callon
Offshore Production, Inc., the several banks and other financial institutions
from time to time parties thereto (the "Banks"), and The Chase Manhattan Bank,
as agent for the Banks, as the same may be amended, modified, supplemented,
extended, restated, replaced, renewed or refinanced from time to time.
"Event of Default" has the meaning specified under "Events of Default and
Remedies."
"GAAP" means United States generally accepted accounting principles set
forth in the opinions and pronouncements of the Accounting Principles board of
the American Institute of Certified Public Accountants and statements' and
pronouncements of the Financial Accounting Standards Board in effect on the date
of the indenture.
"Indebtedness" means any of the following of our or any Restricted
Subsidiary's obligations:
- any obligation, contingent or otherwise, for borrowed money or for the
deferred purchase price of property, assets, securities or services,
including, without limitation, any interest accruing subsequent to an
Event of Default;
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- all obligations (including the notes) evidenced by bonds, notes,
debentures or other similar instruments;
- all indebtedness created or arising under any conditional sale or other
title retention agreement with respect to property acquired (even though
the rights and remedies of the seller or lender under such agreement in
the event of default are limited to repossession or sale of such
property), if and to the extent any of the foregoing indebtedness would
appear as a liability upon a balance sheet prepared in accordance with
GAAP;
- all Capitalized Lease Obligations;
- all liabilities actually due and payable under bankers acceptances and
letters of credit;
- all indebtedness of the type referred to in the preceding five clauses
secured by (or for which the holder of such indebtedness has an existing
right, contingent or otherwise, to be secured by) any Lien upon or
security interest in our or any Restricted Subsidiary's property
(including, without limitation, accounts and contract rights), even
though neither we nor any Restricted Subsidiary has assumed or become
liable for the payment of such indebtedness; and
- any guarantee or endorsement (other than for collection or deposit in the
ordinary course of business) or discount with recourse of, or other
agreement, contingent or otherwise, to purchase, repurchase, or otherwise
acquire, to supply, or advance funds or become liable with respect to,
any indebtedness or any obligation of the type referred to in any of the
preceding six clauses, regardless of whether such obligation would appear
on a balance sheet.
Provided, however, that Indebtedness shall not include:
- Production Payments;
- any liability for gas balancing incurred in the ordinary course of
business;
- our or a Restricted Subsidiary's trade accounts payable or other
obligations in the ordinary course of business in connection with the
obtaining of goods or services; and
- any liability under any and all:
(1) employment or consulting agreements or employee benefit plans or
arrangements; and
(2) futures contracts, forward contracts, swap, cap or collar
contracts, option contracts, or other similar derivative agreements.
"Lien" means any mortgage, charge, pledge, lien (statutory or other),
security interest, hypothecation, assignment for security, claim, or preference
or priority or other encumbrance or similar agreement or preferential
arrangement of any kind or nature whatsoever (including, without limitation, any
agreement to give or grant a Lien or any lease, conditional sale or other title
retention agreement having substantially the same economic effect as any of the
foregoing) upon or with respect to any property of any kind. A Person shall be
deemed to own subject to a Lien any property which that Person has acquired or
holds subject to the interest of a vendor or lessor under any conditional sale
agreement, capital lease or other title retention agreement.
"Material Subsidiary" means any Restricted Subsidiary whose assets or
revenues comprise at least five percent of our and our Restricted Subsidiaries'
assets or revenues on a consolidated basis as of the end of, or for, our most
recently completed fiscal quarter, as determined from time to time.
"Non-payment Event of Default" means any event, other than a Payment Event
of Default, the occurrence of which, with or without notice or the passage of
time, entitles one or more Persons to accelerate the maturity of any Specified
Senior Indebtedness.
"Pari Passu Indebtedness" means any of our Indebtedness that is pari passu
in right of payment to the notes.
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"Payment Event of Default" means any default in the payment or required
prepayment of principal of, or premium, if any, on, or interest on any Specified
Senior Indebtedness when due, whether at final maturity, upon scheduled
installment; upon acceleration or otherwise.
"Permitted Indebtedness" means any of the following:
- Indebtedness outstanding on the date of the indenture, and not repaid or
defeased with the proceeds of the offering of the notes;
- Our Indebtedness to a Restricted Subsidiary and Indebtedness of a
Restricted Subsidiary to us or a Restricted Subsidiary; provided,
however, that upon any event which results in any such Restricted
Subsidiary ceasing to be a Restricted Subsidiary or any subsequent
transfer of any such Indebtedness (except to us or a Restricted
Subsidiary), such Indebtedness shall be deemed, in each case, to be
incurred and shall be treated as an incurrence for purposes of the
"Incurrence of Indebtedness" covenant at the time the Restricted
Subsidiary in question ceased to be a Restricted Subsidiary;
- any guarantee of Senior Indebtedness incurred in compliance with the
"Incurrence of Indebtedness" covenant, by us or a Restricted Subsidiary;
and
- any renewals, substitutions, refinancings or replacements (each, for
purposes of this clause, a "refinancing") by us or a Restricted
Subsidiary of any Indebtedness outstanding on the date of the indenture
(and not repaid or defeased with the proceeds of the offering of the
notes), including any successive refinancings by us or such Restricted
Subsidiary, so long as:
(1) any such new Indebtedness shall be in a principal amount that does
not exceed the principal amount (or, if such Indebtedness being refinanced
provides for an amount less than the principal amount thereof to be due
and payable upon a declaration of acceleration thereof, such lesser amount
as of the date of determination) so refinanced plus the amount of any
premium required to be paid in connection with such refinancing pursuant
to the terms of the Indebtedness refinanced or the amount of any premium
reasonably determined by us or such Restricted Subsidiary as necessary to
accomplish such refinancing, plus the amount of our or such Restricted
Subsidiary's expenses incurred in connection with such refinancing; and
(2) in the case of any refinancing of our Indebtedness that is not
Senior Indebtedness, such new Indebtedness is either pari passu with the
notes or subordinated to the notes at least to the same extent as the
Indebtedness being refinanced; and
(3) such new Indebtedness has an Average Life equal to or longer than
the Average Life of the Indebtedness being refinanced and a final Stated
Maturity equal to or later than the final Stated Maturity of the
Indebtedness being refinanced.
"Permitted Junior Securities" means any of our or any successor obligor's
equity securities or subordinated debt securities with respect to the Senior
Indebtedness provided for by a plan of reorganization or readjustment that, in
the case of any such subordinated debt securities, are subordinated in right of
payment to all Senior Indebtedness that may at the time be outstanding to
substantially the same degree as, or to a greater extent than, the notes are so
subordinated as provided in the indenture.
"Permitted Liens" means any of the following types of Liens:
- Liens existing as of the date the notes are first issued (except to the
extent such Liens secure any Pari Passu Indebtedness or Subordinated
Indebtedness that is repaid or defeased with proceeds of the offering of
the notes), and any renewal, extension or refinancing of any such Lien
provided that thereafter such Lien extends only to the properties that
were subject to such Lien prior to the renewal, extension or refinancing
thereof;
- Liens securing the notes; and
- Liens in favor of us.
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"Person" means any individual, corporation, partnership, joint venture,
association, joint stock company, limited liability company, trust,
unincorporated organization or government or any agency or political subdivision
thereof.
"Production Payments" means the grant or transfer to any Person of a
royalty, overriding royalty, net profits interest, production payment (whether
volumetric or dollar denominated), master limited partnership interest or other
interest in oil and gas properties, which reserves the right to receive all or a
portion of the production or the proceeds from the sale of production
attributable to such properties where the holder of such interest has recourse
solely to such production or proceeds of production, subject to the obligation
of the grantor or transferor to operate and maintain, or cause the subject
interests to be operated and maintained, in a reasonably prudent manner or other
customary standard and/or subject to the obligation of the grantor or transferor
to indemnify for environmental matters.
"Restricted Subsidiary" means any Subsidiary, whether existing on or after
the date of the indenture, unless that Subsidiary is an Unrestricted Subsidiary
or is designated as an Unrestricted Subsidiary pursuant to the terms of the
indenture;
"Senior Indebtedness" means the principal amount of, and interest on and
all other amounts due on or in connection with:
- any of our Indebtedness, whether now outstanding or hereafter created,
incurred, assumed or guaranteed, unless in the instrument creating or
evidencing such Indebtedness or pursuant to which such Indebtedness is
outstanding it is provided that such indebtedness is subordinate in right
of payment or in rights upon liquidation to any other of our
Indebtedness; and
- all renewals, extensions and refundings of any such indebtedness.
"Specified Senior Indebtedness" means:
- all of our Senior Indebtedness in respect of the Credit Facility and any
renewals, amendments, extensions, supplements, modifications, deferrals,
refinancings, or replacements (each, for purposes of this definition, a
"refinancing") thereof by us, including any successive refinancings
thereof by us; and
- any other Senior Indebtedness and any refinancings thereof by us having a
principal amount of at least $5 million as of the date of determination
and provided that the agreements, indentures or other instruments
evidencing such Senior Indebtedness or pursuant to which such Senior
Indebtedness was issued specifically designates such Senior Indebtedness
as "Specified Senior Indebtedness" for purposes of the indenture.
For purposes of this definition, a refinancing of any Specified Senior
Indebtedness shall be treated as Specified Senior Indebtedness only if the
Senior Indebtedness issued in such refinancing ranks or would rank pari passu
with the specified Senior Indebtedness refinanced and only if the Senior
Indebtedness issued in such refinancing is permitted by the covenant described
under "Certain Covenants -- Incurrence of Indebtedness."
"Stated Maturity" with respect to any note or any installment of principal
thereof or interest thereon means the date established by the indenture as the
fixed date on which the principal of such note or such installment of principal
or interest is due and payable, and, when used with respect to any other
Indebtedness or any installment of interest thereon, means the date specified in
the instrument evidencing or governing such Indebtedness as the fixed date on
which the principal of such Indebtedness or such installment of interest is due
and payable.
"Subordinated Indebtedness" means our Indebtedness which is expressly
subordinated in right of payment to the notes, including, without limitation,
the convertible debentures described under the caption "Description of Capital
Stock -- Convertible Debentures" in the accompanying prospectus.
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"Subsidiary" means any corporation of which at the time of determination we
or one or more Subsidiaries own or control directly or indirectly more than 50%
of the Voting Stock.
"2001 Indenture" means that certain indenture dated as of November 27, 1996
between Callon and American Stock Transfer & Trust Company, as trustee, as the
same may have been amended or supplemented from time to time prior to the date
hereof.
"2002 Indenture" means that certain indenture dated as of July 31, 1997
between Callon and American Stock Transfer & Trust Company, as trustee, as the
same may have been amended or supplemented from time to time prior to the date
hereof.
"2004 Indenture" means that certain indenture dated July 20, 1999 between
Callon and American Stock Transfer & Trust Company, as trustee, as the same may
have been amended or supplemented from time to time prior to the date hereof.
"Unrestricted Subsidiary" means:
- any Subsidiary that at the time of determination will be designated an
Unrestricted Subsidiary by the board of directors as provided below; and
- any Subsidiary of an Unrestricted Subsidiary.
The board of directors may designate any Subsidiary as an Unrestricted
Subsidiary so long as neither we nor any Restricted Subsidiary is directly or
indirectly liable pursuant to the terms of any Indebtedness of that Subsidiary
or have any assets or properties which are subject to any Lien securing any
Indebtedness of that Subsidiary. Any designation by the board of directors shall
be evidenced to the trustee by filing a board resolution with the trustee giving
effect to the designation. The board of directors may designate any Unrestricted
Subsidiary as a Restricted Subsidiary if, immediately after giving effect to the
designation:
- no Event of Default shall have occurred and be continuing; and
- we could occur $1.00 of additional Indebtedness (other than Permitted
Indebtedness) under the "Incurrence of Indebtedness" covenant.
"Voting Stock" means stock, interests, participations, rights in or other
equivalents in the equity interests (however designated) with respect to a
corporation having general voting power under ordinary circumstances to elect at
least a majority of the board of directors, managers or trustees of that
corporation, provided that, for the purposes hereof, stock which carries only
the right to vote conditionally on the happening of an event shall not be
considered Voting Stock whether or not such event shall have happened.
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DESCRIPTION OF BANK CREDIT FACILITY AND OTHER INDEBTEDNESS
Bank Credit Facility
Borrowings under our bank credit facility are secured by mortgages covering
substantially all of our producing oil and gas properties. Currently, the credit
facility provides for a $30.0 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. Under our bank credit
facility, the interest rate is equal to the lender's prime rate plus .5%. At our
option, we may fix the interest rate on all or a portion of the outstanding
principal balance at 2% above a defined "Eurodollar" rate for periods up to six
months. The weighted average interest rate for the total debt outstanding at
June 30, 2000 was 8.8%. Under the credit facility, a quarterly commitment fee of
.5% is assessed on the unused portion of the 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.
On September 5, 2000, we executed a commitment letter with a new lender to
provide a $75 million credit facility with an initial borrowing base of $50
million. The new credit facility will contain terms and conditions similar to
our existing credit facility and will mature on October 31, 2001. The new credit
facility is subject to the successful syndication of the lending group. We
intend to pay all amounts outstanding under the existing credit facility with
borrowings under the new credit facility.
Borrowings under the bank credit facility are, and borrowing under our new
credit facility will be, guaranteed by our material subsidiaries. Our existing
bank credit facility has, and our new credit facility will contain, 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. Our new lender
will also require us to maintain financial ratios and conditions.
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."
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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.
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 102% of the principal amount
reducing to par at September 15, 2001, 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.
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UNDERWRITING
We have entered into an underwriting agreement for the offering with the
underwriters named below. Subject to certain conditions, each underwriter has
severally agreed to purchase the principal amount of notes indicated in the
following table.
<TABLE>
<CAPTION>
PRINCIPAL AMOUNT
UNDERWRITERS OF NOTES
------------ ----------------
<S> <C>
Morgan Keegan & Company, Inc. .............................. $24,500,000
A.G. Edwards & Sons, Inc. .................................. 7,500,000
-----------
Total............................................. $32,000,000
===========
</TABLE>
Notes sold by the underwriters to the public will initially be offered at
the initial public offering price set forth on the cover of this prospectus
supplement. Any notes sold by the underwriters to securities dealers may be sold
at a discount from the initial public offering price of up to 2.0% of the
principal amount of the notes. Any such securities dealers may resell any notes
purchased from the underwriters to other brokers or dealers at a discount from
the initial public offering price up to .50% per note from the initial public
offering price. If all the notes are not sold at the initial offering price, the
underwriters may change the offering price and the other selling terms.
The notes are a new issue of securities with no established trading market.
The notes have been approved for listing on the New York Stock Exchange. We have
been advised by the underwriters that the underwriters intend to make a market
in the notes but are not obligated to do so and may discontinue market making at
any time without notice. We cannot assure you about the liquidity of the trading
market for the notes.
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
$4,800,000 aggregate principal amount of notes 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 notes 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 notes as the number set forth next to such
underwriter's name in the preceding table bears to the total number of notes in
the table, and we will be obligated, pursuant to the option, to sell such notes,
to the underwriters.
We have agreed not to sell or otherwise dispose of any of our debt
securities other than the notes offered hereby for a period of 30 days after the
closing date of this offering without the prior written consent of the
underwriters.
In connection with the offering, the underwriters may purchase and sell
notes in the open market. These transactions may include short sales,
stabilizing transactions and purchases to cover positions created by short
sales. Short sales involve the sale by the underwriters of a greater amount of
notes than they are required to purchase in the offering. Stabilizing
transactions consist of certain bids or purchases made for the purpose of
preventing or retarding a decline in the market place of the notes while the
offering is in progress.
The underwriters also may impose a penalty bid. This occurs when a
particular underwriter repays to the underwriters a portion of the underwriting
discount received by it because the underwriters have repurchased notes sold by
or for the account of such underwriter in stabilizing or short covering
transactions.
These activities by the underwriters may stabilize, maintain or otherwise
affect the market price of the notes. As a result, the price of the notes may be
higher than the price that otherwise might exist in the open market. If these
activities are commenced, they may be discontinued by the underwriters at any
time. These transactions may be effected in the over-the-counter market or
otherwise.
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We have agreed to indemnify the several underwriters against various
liabilities, including liabilities under the Securities Act of 1933.
Morgan Keegan & Company, Inc. and A.G. Edwards & Sons, Inc. have acted as
underwriters of past offerings of equity and debt securities by us. Morgan
Keegan & Company, Inc. and A.G. Edwards & Sons, Inc. are acting as co-dealer
managers for our tender offer for our 10% senior subordinated notes due 2001 and
will be compensated for successful tenders of these notes.
VALIDITY OF THE NOTES
The validity of the issuance of the notes will be passed upon for us by our
attorneys, Haynes and Boone, LLP. Certain legal matters will be passed upon for
the underwriters by Vinson & Elkins L.L.P.
EXPERTS
The audited consolidated financial statements as of December 31, 1999, and
for the three years in the period ended December 31, 1999, included and
incorporated by reference in this prospectus supplement and the registration
statement have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their report with respect thereto, and are included
herein and incorporated by reference in reliance upon the authority of said firm
as experts in accounting and auditing in giving said reports.
Information about our estimated net proved reserves and the future net cash
flows attributable to these reserves was prepared by Huddleston & Co., Inc., an
independent petroleum and geological engineering firm and are included herein in
reliance upon their authority as experts in reserves and present values.
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GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
- Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude
oil or other liquid hydrocarbons.
- Bcf -- One billion cubic feet of natural gas.
- Bcfe -- One billion cubic feet of natural gas equivalent, computed on an
appropriate energy equivalent basis that one Bbl equal six Mcf.
- BOE -- One barrel of oil equivalent, converting gas to oil at the ratio
of 6 Mcf of gas to 1 Bbl of oil.
- 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
represents the total number of wells or acres in which we own a working
interest.
- Net oil and gas wells or acres -- Determined by multiplying "gross" oil
and natural gas wells or acres by the working interest that we own in
such wells or acres represented by the underlying properties.
TERMS USED TO ASSIGN A PRESENT VALUE TO OUR RESERVES
- Standardized measure of proved reserves -- The present value, discounted
at 10%, of the pre-tax future net cash flows attributable to estimated
net proved reserves. We calculate this amount by assuming that we will
sell the oil and gas production attributable to the proved reserves
estimated in our independent engineer's reserve report for the prices we
received for the production on the date of the report, unless we had a
contract to sell the production for a different price. We also assume
that the cost to produce the reserves will remain constant at the costs
prevailing on the date of the report. The assumed costs are subtracted
from the assumed revenues resulting in a stream of future net cash flows.
Estimated future income taxes using rates in effect on the date of the
report are deducted from the net cash flow stream. The after-tax cash
flows are discounted at 10% to result in the standardized measure of our
proved reserves. The standardized measure of our proved reserves is
disclosed in our audited 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
S-60
<PAGE> 61
in the future from known oil and natural gas reservoirs under existing
economic and operating conditions.
The Securities and Exchange Commission definition of proved oil and gas
reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (2) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (3) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (4) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
- Proved developed reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
- Proved undeveloped reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required.
TERMS WHICH DESCRIBE THE COST TO ACQUIRE OUR RESERVES
- Reserve replacement costs -- Our reserve replacement costs compare the
amount we spent to explore for oil and gas and to drill and complete
wells during a period, with the increases in reserves during the period.
This amount is calculated by dividing the net change in our evaluated oil
and property costs during a period by the change in proved reserves plus
production over the same period.
TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES
- Reserve life -- A measure of the productive life of an oil and gas
property or a group of oil and gas properties, expressed in years.
Reserve life equals the estimated net proved reserves attributable to a
property or group of properties divided by production from the property
or group of properties for the four fiscal quarters preceding the date as
of which the proved reserves were estimated.
S-61
<PAGE> 62
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
approve the operation and development of the property, while the owners
of the working interests 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-62
<PAGE> 63
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets as of December 31, 1999,
December 31, 1998 and June 30, 2000....................... F-3
Consolidated Statements of Operations for Each of the Three
Years in the Period Ended December 31, 1999 and the Six
Months Ended June 30, 2000 and 1999....................... F-4
Consolidated Statements of Stockholders' Equity for Each of
the Three Years in the Period Ended December 31, 1999 and
the Six Months Ended June 30, 2000........................ F-5
Consolidated Statements of Cash Flows for Each of the Three
Years in the Period Ended December 31, 1999 and the Six
Months Ended June 30, 2000 and 1999....................... F-6
Notes to Consolidated Financial Statements.................. F-7
</TABLE>
F-1
<PAGE> 64
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,
1999 and 1998, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. 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, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana,
February 16, 2000
F-2
<PAGE> 65
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ---------------------
2000 1999 1998
----------- --------- ---------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 9,330 $ 34,671 $ 6,300
Accounts receivable....................................... 13,909 5,362 6,024
Other current assets...................................... 949 1,004 1,924
--------- --------- ---------
Total current assets............................... 24,188 41,037 14,248
--------- --------- ---------
Oil and gas properties, full-cost accounting method:
Evaluated properties...................................... 555,480 511,689 444,579
Less accumulated depreciation, depletion and
amortization.......................................... (369,914) (361,758) (345,353)
--------- --------- ---------
185,566 149,931 99,226
Unevaluated properties excluded from amortization......... 51,576 44,434 42,679
--------- --------- ---------
Total oil and gas properties....................... 237,142 194,365 141,905
--------- --------- ---------
Pipeline and other facilities, net........................ 5,699 5,860 6,182
Other property and equipment, net......................... 1,555 1,450 1,753
Deferred tax asset........................................ 12,772 14,995 16,348
Long-term gas balancing receivable........................ 343 243 199
Other assets, net......................................... 1,698 1,927 1,017
--------- --------- ---------
Total assets....................................... $ 283,397 $ 259,877 $ 181,652
========= ========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities.................. $ 17,186 $ 16,786 $ 11,257
Undistributed oil and gas revenues........................ 1,867 2,082 1,720
Accrued net profits interest payable...................... 1,868 1,676 129
Current Maturities of long term debt...................... 22,000 -- --
--------- --------- ---------
Total current liabilities.......................... 42,921 20,544 13,106
--------- --------- ---------
Accounts payable and accrued liabilities to be
refinanced.............................................. -- -- 3,000
Long-term debt............................................ 100,250 100,250 78,250
Deferred revenue on sale of production payment interest... 9,671 12,080 --
Accrued retirement benefits............................... 1,996 2,107 2,323
Long-term gas balancing payable........................... 574 516 489
--------- --------- ---------
Total liabilities.................................. 155,412 135,497 97,168
--------- --------- ---------
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares
authorized; 1,040,461 shares of Convertible Exchangeable
Preferred Stock, Series A issued and outstanding at June
30, 2000 and 1,045,461 and 1,255,811 outstanding at
December 31, 1999 and 1998, respectively, with a
liquidation preference of $26,011,525 at June 30,
2000.................................................... 10 11 13
Common Stock, $.01 par value; 20,000,000 shares
authorized; 12,277,211, 12,239,238 and 8,178,406 shares
outstanding at June 30, 2000, December 1999 and 1998,
respectively............................................ 123 122 82
Treasury stock (99,078 shares at cost).................... (1,183) (1,183) (915)
Capital in excess of par value............................ 149,817 149,425 109,429
Retained earnings (deficit)............................... (20,782) (23,995) (24,125)
--------- --------- ---------
Total stockholders' equity......................... 127,985 124,380 84,484
--------- --------- ---------
Total liabilities and stockholders' equity......... $ 283,397 $ 259,877 $ 181,652
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 66
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
----------------- ----------------------------
2000 1999 1999 1998 1997
------- ------- ------- -------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales......................... $23,760 $16,537 $37,140 $ 35,624 $42,130
Interest and other........................ 1,074 868 1,853 2,094 1,508
------- ------- ------- -------- -------
Total revenues.................... 24,834 17,405 38,993 37,718 43,638
------- ------- ------- -------- -------
Cost and expenses:
Lease operating expenses.................. 4,154 3,486 7,536 7,817 8,123
Depreciation, depletion and
amortization........................... 8,317 7,952 16,727 19,284 16,488
General and administrative................ 1,972 2,440 4,575 5,285 4,433
Interest.................................. 3,846 2,471 6,175 1,925 1,957
Accelerated vesting and retirement
benefits............................... -- -- -- 5,761 --
Impairment of oil and gas properties...... -- -- -- 43,500 --
------- ------- ------- -------- -------
Total costs and expenses.......... 18,289 16,349 35,013 83,572 31,001
------- ------- ------- -------- -------
Income (loss) from operations............... 6,545 1,056 3,980 (45,854) 12,637
Income tax expense (benefit).............. 2,226 359 1,353 (15,100) 4,200
------- ------- ------- -------- -------
Net income (loss)........................... 4,319 697 2,627 (30,754) 8,437
Preferred stock dividends................... 1,105 1,386 2,497 2,779 2,795
------- ------- ------- -------- -------
Net income (loss) available to common
shares.................................... $ 3,214 $ (689) $ 130 $(33,533) $ 5,642
======= ======= ======= ======== =======
Net income (loss) per common share:
Basic..................................... $ .26 $ (.08) $ .01 $ (4.17) $ .91
======= ======= ======= ======== =======
Diluted................................... $ .26 $ (.08) $ .01 $ (4.17) $ .88
======= ======= ======= ======== =======
Shares used in computing net income (loss)
per common share:
Basic..................................... 12,163 8,462 8,976 8,034 6,194
======= ======= ======= ======== =======
Diluted................................... 12,398 8,462 9,075 8,034 6,422
======= ======= ======= ======== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 67
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, 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).................. -- -- -- -- -- 2,627
Sale of common stock............... -- 37 -- -- 40,994 --
Preferred stock dividends.......... -- -- -- -- -- (2,222)
Shares issued pursuant to employee
benefit and option plan......... -- -- -- -- 274 --
Employee stock purchase plan....... -- -- -- -- 67 --
Restricted stock plan.............. -- (2) -- -- (1,613) --
Conversion of preferred shares to
common.......................... (2) 5 -- -- 274 (275)
Stock buyback plan................. -- -- (268) -- -- --
--- ---- ------- ------- -------- --------
Balances, December 31, 1999.......... 11 122 (1,183) -- 149,425 (23,995)
Net income (loss).................. -- -- -- -- -- 4,319
Preferred stock dividends.......... -- -- -- -- -- (1,105)
Shares issued pursuant to employee
benefit plan and option plan.... -- -- -- -- 260 --
Employee stock purchase plan....... -- -- -- -- 54 --
Sale of common stock............... -- -- -- -- 75 --
Tax benefits related to stock
compensation plans.............. -- -- -- -- 3 --
Conversion of preferred shares to
common.......................... (1) 1 -- -- -- --
--- ---- ------- ------- -------- --------
Balances, June 30, 2000
(Unaudited)........................ $10 $123 $(1,183) $ -- $149,817 $(20,782)
=== ==== ======= ======= ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 68
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS
ENDED
JUNE 30, YEARS ENDED DECEMBER 31,
------------------- ------------------------------
2000 1999 1999 1998 1997
-------- -------- -------- -------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss).......................... $ 4,319 $ 697 $ 2,627 $(30,754) $ 8,437
Adjustments to reconcile net income (loss)
to net cash provided by operating
activities:
Depreciation, depletion and
amortization.......................... 8,532 8,210 17,232 19,791 16,924
Impairment of oil and gas properties..... -- -- -- 43,500 --
Amortization of deferred costs........... 463 276 707 619 467
Amortization of deferred production
payment revenue....................... (2,409) (252) (2,710) -- --
Deferred income tax expense (benefit).... 2,223 359 1,353 (15,100) 4,200
Noncash compensation related to stock
compensation plans.................... 260 141 275 7,583 1,224
Changes in current assets and
liabilities:
Accounts receivable................... (2,333) 737 662 6,144 493
Other current assets.................. 55 985 920 (1,201) (207)
Current liabilities................... (1,773) (1,532) 1,981 (876) (3,809)
Change in gas balancing receivable....... (100) (25) (44) 43 418
Change in gas balancing payable.......... 58 2 27 85 14
Change in other long-term liabilities.... (111) (108) (216) -- 249
Change in other assets, net.............. (234) (168) (1,617) (129) (1,073)
-------- -------- -------- -------- --------
Cash provided (used) by operating
activities............................ 8,950 9,322 21,197 29,705 27,337
-------- -------- -------- -------- --------
Cash flows from investing activities:
Capital expenditures....................... (55,684) (26,366) (51,709) (63,501) (85,999)
Cash proceeds from sale of mineral
interests................................ 366 -- -- 9,909 4,450
-------- -------- -------- -------- --------
Cash provided (used) by investing
activities............................ (55,318) (26,366) (51,709) (53,592) (81,549)
-------- -------- -------- -------- --------
Cash flows from financing activities:
Equity issued related to employee stock
plans.................................... 132 66 68 414 90
Purchase of treasury shares................ -- (262) (268) (915) --
Payments on debt........................... -- (42,500) -- (49,200)
Increase in debt........................... 22,000 21,000 64,500 18,000 85,200
Common stock canceled...................... -- (1,615) (1,615) (130) (422)
Sale of common stock....................... -- -- 41,031 -- 29,267
Cash dividends on preferred stock.......... (1,105) (1,111) (2,333) (2,779) (2,795)
-------- -------- -------- -------- --------
Cash provided (used) by financing
activities............................ 21,027 18,078 58,883 14,590 62,140
-------- -------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents................................ (25,341) 1,034 28,371 (9,297) 7,928
Cash and cash equivalents:
Balance, beginning of period............... 34,671 6,300 6,300 15,597 7,669
-------- -------- -------- -------- --------
Balance, end of period..................... $ 9,330 $ 7,334 $ 34,671 $ 6,300 $ 15,597
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 69
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION WITH RESPECT TO THE PERIODS ENDING JUNE 30, 2000 AND 1999 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> 70
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, 1999 and 1998 and June
30, 2000, 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> 71
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 was $38,000 at June 30, 2000, December 31, 1999 and 1998,
respectively. Net recoveries were $2,000 in 1998 and net charge offs were
$357,000 in 1997. There were no provisions to expense in the three year period
ended December 31, 1999 and the six month period ending June 30, 2000.
For the year ended December 31, 1999, three companies purchased 12%, 16%
and 29%, 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, EI 335, HI A494 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, 1999. During the years ended December 31, 1999, 1998 and 1997, the Company
made cash payments of $9,013,000, $6,229,000 and $4,167,000, respectively, for
interest charged on its indebtedness and $5,110,000 for the six months ended
June 30, 2000.
Per Share Amounts
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
1999 and 1997 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 the six
months ended June 30, 1999 and for the year ended December 31, 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 its antidilutive effect on diluted income or loss per
share.
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,
---------------- --------------------------
2000 1999 1999 1998 1997
------- ------ ------ -------- ------
<S> <C> <C> <C> <C> <C>
(a) Net income (loss) available for common
stock...................................... $ 3,214 $ (689) $ 130 $(33,533) $5,642
(b) Weighted average shares outstanding........ 12,163 8,462 8,976 8,034 6,194
(c) Dilutive impact of stock options........... 235 -- 99 -- 228
(d) Total diluted shares....................... 12,398 8,462 9,075 8,034 6,422
Stock options excluded due to antidilutive
impact..................................... -- 39 -- 163 --
Basic earnings (loss) per share(a/b)...... $ 0.26 $(0.08) $ 0.01 $ (4.17) $ 0.91
Diluted earnings (loss) per share(a/d).... $ 0.26 $(0.08) $ 0.01 $ (4.17) $ 0.88
</TABLE>
F-9
<PAGE> 72
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1999 and 1998 and
June 30, 2000. Fair value of long-term debt (specifically the 10%, 10.125% and
the 10.25% 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, 1999 indicated a $457,000 market value
benefit to the Company based on market prices at that date.
Accounts Payable and Accrued Liabilities -- Long-Term
Approximately $3,000,000 of current accounts payable and accrued
liabilities at December 31, 1998 related to long-term assets, primarily oil and
gas properties, were financed subsequent to year-end 1998 with long-term debt
and therefore have been classified 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
Company's management determined that no valuation allowance was necessary in
1999 and 1998. Accordingly, the Company has recorded a deferred tax asset at
December 31, 1999 and 1998 as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------
1999 1998
------- -------
(IN THOUSANDS)
<S> <C> <C>
Federal net operating loss carry forward.................... $13,143 $ 7,916
Statutory depletion carryforward............................ 4,087 4,083
Temporary differences:
Oil and gas properties.................................... (2,200) 3,979
Pipeline and other facilities............................. (2,051) (2,164)
Non-oil and gas property.................................. (102) (101)
Other..................................................... 2,118 2,635
------- -------
Total tax asset............................................. 14,995 16,348
Valuation allowance......................................... -- --
------- -------
Net tax asset..................................... $14,995 $16,348
======= =======
</TABLE>
At December 31, 1999, the Company had, for federal tax reporting purposes,
net operating loss carryforwards ("NOL") of $37.6 million which expire in 2000
through 2012. Additionally, the Company had available for tax reporting purposes
$11.7 million in statutory depletion deductions which can be carried forward for
an indefinite period.
F-10
<PAGE> 73
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The provision for income taxes at the Company's effective tax rate differed
from the provision for income taxes at the statutory rate as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1999 1998 1997
------ -------- ------
(IN THOUSANDS)
<S> <C> <C> <C>
Computed expense (benefit) at the expected statutory
rate................................................... $1,353 $(15,590) $4,296
Other.................................................... -- 490 (96)
------ -------- ------
Deferred income tax expense (benefit).................... $1,353 $(15,100) $4,200
====== ======== ======
</TABLE>
4. DEFERRED REVENUE ON SALE OF PRODUCTION PAYMENT INTEREST
In June 1999, the Company acquired a working interest in the Mobile Block
864 Area where the Company already owned an interest. Concurrent with this
acquisition, the seller received a volumetric production payment, valued at
approximately $14.8 million, from production attributable to a portion of the
Company's interest in the area over a 39-month period. The Company deferred the
revenue associated with the sale of this production payment interest because a
substantial obligation for future performance exists. Under the terms of the
sale, the Company is obligated to deliver the production volumes free and clear
of royalties, lease operating expenses, production taxes and all capital costs.
The production payment was recorded at the present value of the volumetric
production committed to the seller at market value and, beginning in June 1999,
is amortized to oil and gas sales on the units-of-production method as
associated hydrocarbons are delivered.
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
<TABLE>
<CAPTION>
DECEMBER 31,
JUNE 30, ------------------
2000 1999 1998
-------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Credit Facility....................................... $ 22,100 $ 100 $18,100
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 --
-------- -------- -------
122,250 100,250 78,250
Less: current portion................................. 22,000 -- --
-------- -------- -------
$100,250 $100,250 $78,250
======== ======== =======
</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 $30 million
borrowing base ("Borrowing Base") which is adjusted periodically on the basis of
a discounted present value of future net cash flows attributable to the
Company's proved producing oil and gas reserves. Pursuant to the Credit
Facility, depending upon the percentage of the unused portion of the borrowing
base, the interest rate is equal to the lender's prime rate plus 0.50% (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 2% above a defined "Eurodollar" rate for
periods up to six months. The weighted average interest rate for the Credit
Facility debt outstanding at June 30, 2000, December 31, 1999 and 1998 was
8.77%, 9.00% and 6.68%, respectively. Under the Credit Facility, a commitment
fee of .50% per annum on the unused portion of the Borrowing Base is payable
quarterly. The Company may borrow, pay, reborrow and repay under the Credit
Facility
F-11
<PAGE> 74
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
until October 31, 2000, on which date, the Company must repay in full all
amounts then outstanding. Therefore, the entire amount outstanding at June 30,
2000 has been classified as a current liability in the financial statements.
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 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 completed its sale of $40 million of Senior
Subordinated Notes due 2004 at 10.25%. The net proceeds of approximately $38.2
million were used to pay down the Credit Facility at that time. These notes are
not entitled to any mandatory sinking fund payments and are subject to
redemption at the Company's option at par plus unpaid interest at any time after
March 15, 2001. The notes are listed on the New York Stock Exchange under the
symbol "CPE 04" and are subject to a change of control clause that obligates the
Company to repurchase the 10.25% notes for 101% of par should a change of
control occur. Interest is paid quarterly beginning September 15, 1999.
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 was in
compliance with these covenants at December 31, 1999 and June 30, 2000.
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
$1,559,000 was recognized as a reduction of oil and gas revenue and $1,886,000
and $2,466,000 was recognized as additional oil and gas revenue in 1999, 1998
and 1997, respectively. Approximately $886,000 was recognized as a reduction of
oil and gas revenue, and $730,000 was recognized as additional oil and gas
revenue in the first six months of 2000 and 1999, respectively.
At June 30, 2000, the Company had open natural gas collar contracts with
third parties whereby minimum floor prices and maximum ceiling prices are
contracted and applied to related contract volumes.
F-12
<PAGE> 75
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
These agreements in effect for 2000 are for average gas volumes of 350,000 Mcf
per month through October 2000 at (on average) a ceiling price of $2.72 and
floor price of $2.50. In addition, the Company had no open oil collar contracts
at June 30, 2000.
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, 2000, total estimated site
restoration, dismantlement and abandonment costs were approximately $6,300,000,
net of expected salvage value. Substantially all such costs are expected to be
funded through the Trusts' funds, all of which will be accessible to the Company
when abandonment work begins. In addition as a working interest owner and/or
operator of oil and gas properties, the Company is responsible for the cost of
abandonment of such properties. See Note 2.
The Company, as part of the Consolidation, entered into Registration Rights
Agreements whereby the former stockholders of certain of the Constituent
Entities are entitled to require the Company to register Common Stock of the
Company owned by them with the Securities and Exchange Commission for sale to
the public in a firm commitment public offering and generally to include shares
owned by them, at no cost, in registration statements filed by the Company.
Costs of the offering will not include discounts and commissions, which will be
paid by the respective sellers of the Common Stock.
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, ------------------------------
2000 1999 1998 1997
---------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Capitalized costs incurred:
Evaluated Properties --
Beginning of period balance..................... $511,689 $444,579 $398,046 $322,970
Property acquisition costs...................... 873 24,153 9,464 51,751
Exploration costs............................... 42,425 37,427 42,617 13,620
Development costs............................... 858 5,530 4,361 14,155
Sale of mineral interest........................ (365) -- (9,909) (4,450)
-------- -------- -------- --------
End of period balance........................... $555,480 $511,689 $444,579 $398,046
======== ======== ======== ========
Unevaluated Properties (excluded from the full-cost
pool) --
Beginning of period balance..................... $ 44,434 $ 42,679 $ 35,339 $ 26,235
Additions....................................... 10,267 4,890 11,156 16,924
Capitalized interest and general administrative
costs......................................... 4,210 7,120 8,955 5,163
Transfer to evaluated........................... (7,335) (10,255) (12,771) (12,983)
-------- -------- -------- --------
End of period balance........................... $ 51,576 $ 44,434 $ 42,679 $ 35,339
======== ======== ======== ========
Accumulated depreciation, depletion and
amortization --
Beginning of period balance..................... $361,758 $345,353 $282,891 $266,716
Provision charged to expense.................... 8,156 16,405 18,962 16,175
Impairment of oil and gas properties............ -- -- 43,500 --
-------- -------- -------- --------
End of period balance........................... $369,914 $361,758 $345,353 $282,891
======== ======== ======== ========
</TABLE>
F-13
<PAGE> 76
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Unevaluated property costs, primarily lease acquisition costs incurred at
federal and state lease sales, unevaluated drilling costs and capitalized
interest and general and administrative costs being excluded from the
amortizable evaluated property base consisted of $13.1 million incurred in 1999,
$12.1 million incurred in 1998 and $19.2 million incurred in 1997 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 (thousand
cubic feet of gas equivalent) amounted to $.99, $1.19, and $1.02 for the years
ended December 31, 1999, 1998 and 1997, respectively, and $1.05 and $1.01 for
the six months ended June 30, 2000 and 1999, respectively.
Impairment of Oil and Gas Properties
Under full-cost accounting rules, the capitalized costs of proved oil and
gas properties are subject to a "ceiling test," which limits such costs to the
estimated present value net of related tax effects, discounted at a 10 percent
interest rate, of future net cash flows from proved reserves, based on current
economic and 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 at December 31, 1998.
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,
1999 and 1998 the Trusts' assets (all cash and investments) totaled $5,690,000
and $6,360,000, respectively and $6,300,000 at June 30, 2000, 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
F-14
<PAGE> 77
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 $466,000, $468,000 and $438,000 in
the years 1999, 1998 and 1997, 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. These options have an expiration date 10 years from the date of grant.
On August 23, 1996, the Board of Directors of the Company approved and
adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996
Plan"). The 1996 Plan 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. Unvested options are
subject to forfeiture upon certain termination of employment events and expire
10 years from date of grant.
F-15
<PAGE> 78
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 Financial Accounting Standards Board 123 ("FAS 123") "Accounting for
Stock-Based Compensation," the Company's net income and earnings per common
share would have been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------------
1999 1998 1997
--------- ---------- --------
(IN THOUSANDS, EXCEPT PER SHARE
DATA)
<S> <C> <C> <C>
Net income (loss):
As reported........................................... $ 130 $(33,533) $5,642
Pro Forma............................................. (1,212) (34,421) 4,977
Basic earnings (loss) per share:
As reported........................................... 0.01 (4.17) 0.91
Pro Forma............................................. (0.14) (4.28) 0.80
Diluted earnings (loss) per share:
As reported........................................... 0.01 (4.17) 0.88
Pro Forma............................................. (0.14) (4.28) 0.77
</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, 1999, 1998 and 1997 and changes during the years then ended is presented in
the table and narrative below:
<TABLE>
<CAPTION>
1999 1998 1997
--------------------- --------------------- ---------------------
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........................ 1,266,000 $11.00 1,041,000 $11.19 1,030,000 $11.10
Granted..................... 270,500 $ 9.27 225,000 $10.08 20,000 $15.31
Exercised................... -- -- -- -- (9,000) $10.00
Forfeited................... -- -- -- -- -- --
Expired..................... -- -- -- -- -- --
---------- ------ ---------- ------ ---------- ------
Outstanding, end of year...... 1,536,500 $10.60 1,266,000 $11.00 1,041,000 $11.19
========== ====== ========== ====== ========== ======
Exercisable, end of year...... 1,247,600 $10.47 802,250 $10.90 621,000 $10.65
========== ====== ========== ====== ========== ======
Weighted average fair value of
options granted............. $ 4.94 $ 4.31 $ 6.30
========== ========== ==========
</TABLE>
At December 31, 1999, 1,496,500 of the 1,536,500 options outstanding have
exercise prices between $9 and $13.50 with a weighted average exercise price of
$10.50 and a weighted average remaining contractual life of 6.6 years. 1,207,600
of these options are exercisable at a weighted average exercise price of $10.34.
The remaining 40,000 options have exercise prices between $13.50 and $15.31 with
a weighted average exercise price of $14.53. All of these options are
exercisable.
F-16
<PAGE> 79
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1999, 1998 and 1997.
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Risk free interest rate..................................... 6.2% 5.1% 6.8%
Expected life (years)....................................... 7.0 7.0 4.0
Expected volatility......................................... 46.0% 28.8% 41.1%
Expected dividends.......................................... -- -- --
</TABLE>
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 and $714,000 in
1997 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 $3.5 million 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 by the compensation committee of the Board of
Directors 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
F-17
<PAGE> 80
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 502,637 shares of the Company's Common Stock. Any noncash premium
negotiated in excess of the conversion rate was recorded as additional preferred
stock dividends.
In November 1999, the Company sold 3,680,000 shares of Common Stock in a
public offering at a price of $11.875 per share. Cash proceeds received by the
Company were $41.1 million net of the underwriting discount and offering costs.
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 1999, 1998 and
1997 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.
The 1999 estimates have been adjusted (per SEC guidelines) to exclude (i)
volumes (approximately 5.8 billion cubic feet of natural gas) and (ii) future
cash inflows of approximately $12.1 million associated with the volumetric
production payment described in Note 4. The adjustments resulted in a reduction
of approximately $7.0 million in standardized measure of discounted net cash
flows associated with this volumetric production payment.
There are numerous uncertainties inherent in establishing quantities of
proved reserves. The following reserve data represent estimates only and should
not be construed as being exact. In addition, the present values should not be
construed as the current market value of the Company's oil and gas properties or
the cost that would be incurred to obtain equivalent reserves.
F-18
<PAGE> 81
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Estimated Reserves
Changes in the estimated net quantities of crude oil and natural gas
reserves, all of which are located onshore and offshore in the continental
United States, are as follows:
RESERVE QUANTITIES
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
---------------------------
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period.................................... 6,898 3,402 3,819
Revisions to previous estimates........................ (686) (99) (151)
Purchase of reserves in place.......................... 2,629 162 --
Sales of reserves in place............................. -- (1,531) (78)
Extensions and discoveries............................. 15,323 5,274 274
Production............................................. (330) (310) (462)
------- ------- -------
End of period.......................................... 23,834 6,898 3,402
======= ======= =======
Natural Gas (MMcf):
Beginning of period.................................... 88,030 88,738 50,424
Revisions to previous estimates........................ (11,492) (8,631) (11,174)
Purchase of reserves in place.......................... 4,733 4,414 52,485
Sales of reserves in place............................. -- (684) (164)
Extensions and discoveries............................. 42,662 18,229 10,281
Production............................................. (13,312) (14,036) (13,114)
------- ------- -------
End of period.......................................... 110,621 88,030 88,738
======= ======= =======
Proved developed reserves:
Crude Oil (MBbls):
Beginning of period.................................... 1,774 2,976 3,385
======= ======= =======
End of period.......................................... 1,376 1,774 2,976
======= ======= =======
Natural Gas (MMcf):
Beginning of period.................................... 76,895 88,010 49,491
======= ======= =======
End of period.......................................... 76,295 76,895 88,010
======= ======= =======
</TABLE>
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.
F-19
<PAGE> 82
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
--------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash inflows......................................... $ 847,930 $256,325 $285,953
Future costs --
Production................................................ (207,615) (67,192) (63,709)
Development and net abandonment........................... (123,749) (36,581) (12,984)
--------- -------- --------
Future net inflows before income taxes...................... 516,567 152,552 209,260
Future income taxes......................................... (109,238) -- (32,781)
--------- -------- --------
Future net cash flows....................................... 407,329 152,552 176,479
10% discount factor......................................... (151,007) (52,801) (48,400)
--------- -------- --------
Standardized measure of discounted future net cash flows.... $ 256,322 $ 99,751 $128,079
========= ======== ========
</TABLE>
CHANGES IN STANDARDIZED MEASURE
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31
------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure -- beginning of period................. $ 99,751 $128,079 $130,169
Sales and transfers, net of production costs................ (27,076) (27,807) (34,006)
Net change in sales and transfer prices, net of production
costs..................................................... 57,246 (33,029) (66,880)
Exchange and sale of in place reserves...................... -- (4,445) (2,428)
Purchases, extensions, discoveries, and improved recovery,
net of future production and development costs............ 181,185 24,294 90,550
Revisions of quantity estimates............................. (22,438) (9,409) (13,751)
Accretion of discount....................................... 9,975 13,645 16,017
Net change in income taxes.................................. (29,492) 7,926 21,633
Changes in production rates, timing and other............... (12,829) 497 (13,225)
-------- -------- --------
Standardized measure -- end of period....................... $256,322 $ 99,751 $128,079
======== ======== ========
</TABLE>
F-20
<PAGE> 83
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>
1999
Total revenues.......................................... $ 8,374 $9,031 $10,584 $11,004
Total costs and expenses................................ 7,659 8,690 8,986 9,678
Income tax expense (benefit)............................ 243 116 543 451
Net income (loss)....................................... 472 225 1,055 875
Net income (loss) per share -- basic.................... (0.04) (0.04) 0.06 0.03
Net income (loss) per share -- diluted.................. (0.04) (0.04) 0.06 0.03
1998
Total revenues.......................................... $11,492 $9,733 $ 9,339 $ 7,154
Total costs and expenses................................ 9,664 8,606 7,919 57,383
Income tax expense (benefit)............................ 621 380 487 (16,588)
Net income (loss)....................................... 1,207 747 933 (33,641)
Net income (loss) per share -- basic.................... 0.06 0.01 0.03 (4.27)
Net income (loss) per share -- diluted.................. 0.06 0.01 0.03 (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 (loss)....................................... 3,682 1,209 1,192 2,354
Net income (loss) per share -- basic.................... 0.50 0.08 0.08 0.25
Net income (loss) per share -- diluted.................. 0.39 0.08 0.08 0.24
</TABLE>
During the fourth quarter of 1998, the Company recorded a non-cash
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 at December 31, 1998. See Note 8.
F-21
<PAGE> 84
[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> 85
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............................................. 3
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................................ 13
Description of Securities Warrants.......................... 17
Description of Securities Purchase Contracts and Securities
Purchase Units and Prepaid Securities..................... 18
Plan of Distribution........................................ 18
Experts..................................................... 20
Legal Matters............................................... 20
</TABLE>
i
<PAGE> 86
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
1
<PAGE> 87
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.
2
<PAGE> 88
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 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.
3
<PAGE> 89
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;
4
<PAGE> 90
- 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)
5
<PAGE> 91
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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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.
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
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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.
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
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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 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
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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.
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
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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.
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
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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.
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.
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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 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
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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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WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE INFORMATION DIFFERENT FROM THAT
CONTAINED IN THIS PROSPECTUS. YOU MUST NOT RELY ON ANY UNAUTHORIZED INFORMATION
OR REPRESENTATIONS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR SALE OF THE
NOTES MEANS THAT INFORMATION CONTAINED IN THIS PROSPECTUS IS CORRECT AFTER THE
DATE OF THIS PROSPECTUS. THIS PROSPECTUS IS NOT AN OFFER TO SELL OR SOLICITATION
OF AN OFFER TO BUY THESE NOTES IN ANY CIRCUMSTANCES UNDER WHICH THE OFFER OR
SOLICITATION IS UNLAWFUL.
------------------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PROSPECTUS SUPPLEMENT PAGE
<S> <C>
Prospectus Supplement Summary.............. S-3
Risk Factors............................... S-10
Forward-Looking Statements................. S-16
Use of Proceeds............................ 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-27
Management................................. S-33
Beneficial Ownership of Our Common and
Preferred Stock.......................... S-35
Description of the Notes................... S-39
Description of Bank Credit Facility and
Other Indebtedness....................... S-56
Underwriting............................... S-58
Validity of the Notes...................... S-59
Experts.................................... S-59
Glossary of Oil and Gas Terms.............. S-60
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............................ 3
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............... 13
Description of Securities Warrants......... 17
Description of Securities Purchase
Contracts and Securities Purchase Units
and Prepaid Securities................... 18
Plan of Distribution....................... 18
Experts.................................... 20
Legal Matters.............................. 20
</TABLE>
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$32,000,000
[CALLON LOGO]
CALLON PETROLEUM COMPANY
11% SENIOR SUBORDINATED NOTES
DUE 2005
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PROSPECTUS
---------------------
MORGAN KEEGAN & COMPANY, INC.
A.G. EDWARDS & SONS, INC.
October 23, 2000
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