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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
COMMISSION FILE NUMBER 0-25192
CALLON PETROLEUM COMPANY
(Exact name of Registrant as specified in its charter)
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DELAWARE 64-0844345
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
200 NORTH CANAL STREET
NATCHEZ, MISSISSIPPI 39120 (601) 442-1601
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(Address of Principal Executive (Registrant's telephone number
Offices)(Zip Code) including area code)
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Securities registered pursuant to Section 12(b) of the Act:
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TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED
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Convertible Exchangeable Preferred Stock, New York Stock Exchange
Series A, Par Value $.01 Per Share
Common Stock, Par Value $.01 Per Share New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X]. No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of the voting stock held by nonaffiliates of the
registrant was approximately $145,472,700 as of March 13, 2000 (based on the
last reported sale price of such stock on the New York Stock Exchange).
As of March 13, 2000, there were 12,264,101 shares of the Registrant's Common
Stock, par value $.01 per share, outstanding.
Document incorporated by reference: Portions of the definitive Proxy Statement
of Callon Petroleum Company (to be filed no later than 120 days after December
31, 1999) relating to the Annual Meeting of Stockholders to be held on May 9,
2000, which is incorporated into Part III of this Form 10-K.
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This report includes "forward-looking statements" within the meaning of Section
21E of the Securities Exchange Act of 1934. All statements other than statements
of historical fact included in this report regarding the Company's financial
position and cash requirements, estimated quantities and net present values of
reserves, business strategy, plans and objectives for future operations and
covenant compliance, are forward-looking statements. The Company can give no
assurances that the assumptions upon which such forward-looking statements are
based will prove to have been correct. Important factors that could cause actual
results to differ materially from the Company's expectations ("Cautionary
Statements") are disclosed below under "Risk Factors" and elsewhere in this
report and in other filings made by the Company with the Securities and Exchange
Commission (the "Commission"). The Cautionary Statements expressly qualify all
subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf.
PART I.
BUSINESS OF THE COMPANY
ITEM 1. BUSINESS
OVERVIEW
Callon Petroleum Company (the "Company") has been engaged in the acquisition,
development and exploration of oil and gas properties since 1950. The Company's
properties are geographically concentrated primarily offshore in the Gulf of
Mexico and onshore in Louisiana and Alabama. The Company was formed under the
laws of the state of Delaware in 1994 through the consolidation of a publicly
traded limited partnership, a joint venture with a consortium of European
institutional investors and an independent energy company owned by certain
members of current management (the "Consolidation"). As used herein, the
"Company" refers to Callon Petroleum Company and its predecessors and
subsidiaries unless the context requires otherwise.
Beginning in 1989, the Company increased its reserves through the acquisition of
producing properties that were geologically complex, had (or were analogous to
fields with) an established production history from stacked pay zones and were
candidates for exploitation. The Company focused on reducing operating costs and
implementing production enhancements through the application of technologically
advanced production and recompletion techniques.
Over the past four years, the Company has also placed emphasis on the
acquisition of acreage with exploration and development drilling opportunities.
The Company acquired an infrastructure of production platforms, gathering
systems and pipelines to minimize development expenditures of these drilling
opportunities. The Company also joined with other industry partners, primarily
Murphy Exploration and Production, Inc., ("Murphy") to explore federal offshore
blocks acquired in the Gulf of Mexico. The Company currently has 65 federal
offshore blocks in inventory. During this period, Callon has drilled 20
productive wells and 10 dry holes for a total of 30 wells and a success rate of
67%. These 20 productive wells include three onshore, 14 in the Gulf of Mexico
shelf area and three in the deepwater region of the Gulf. During 1999, seven of
these productive wells contributed 135 billion cubic feet of natural gas
equivalent ("Bcfe") of reserve additions. These additions from the drill bit
contributed to a net reserve replacement cost of $0.46 per million cubic feet of
natural gas equivalent ("Mcfe").
The major focus of the Company's future operations is expected to be the
exploration for and development of oil and gas properties, primarily in the Gulf
of Mexico.
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BUSINESS STRATEGY
The Company's goals are to increase reserves, production, cash flow and earnings
at low reserve replacement costs and it seeks to achieve these goals through the
following strategies:
o Assemble and explore a balanced portfolio of projects in the Gulf of
Mexico composed of:
-Controlling working interest in projects with low exploration risk and
low drilling and completion costs targeting reserve deposits of between
3 and 10 billion cubic feet of natural gas ("Bcf") in the shallow
Miocene area at well depths of less than 4,000 feet;
-Significant working interests in projects with moderate exploration
risk and higher drilling and completion costs targeting reserve deposits
of between 10 and 100 Bcfe in the OCS area at well depths of between
7,000 and 17,000 feet; and
-Smaller working interests in projects with high exploration risk and
high drilling and completion costs targeting large reserve deposits in
the deep water area of the Gulf of Mexico.
o Acquire at low costs, additional working interest, gathering systems,
pipelines, production facilities and other infrastructure in areas in
which it operates. Ownership of these facilities enables the Company to
reduce the costs of completing wells and to control the timing of the
development of our properties.
o Utilize the latest available technology. The Company's geoscientists and
petroleum engineers have developed an expertise with advanced
technologies, including 3-D seismic interpretation and computer-aided
exploration.
o Maintain financial flexibility. The Company strives to maintain a
substantial unused borrowing capacity under its bank credit facility by
periodically refinancing our bank debt in the capital markets by issuing
both debt and equity securities.
EXPLORATION AND DEVELOPMENT ACTIVITIES
GULF OF MEXICO DEEPWATER
Habanero, Garden Banks Block 341
During February 1999 the initial test well on the Company's Habanero prospect
encountered over 200 feet of net pay. Located in 2,000 feet of water, the well
was drilled to a measured depth of 21,158 feet. This discovery was the second
deepwater success for the Company. Callon owns an 11.25% working interest in the
well. It is operated by Shell Deepwater Development Inc., which owns a 55%
working interest, with the remaining working interest being owned by Murphy.
Medusa, Mississippi Canyon 538/582
During September 1999 the initial test well on the Company's Medusa prospect
encountered over 120 feet of net pay. Located in 2,100 feet of water, the well
was drilled to a measured depth of 16,241 feet. Delineation drilling
accomplished by sidetracking from the original well bore encountered an
additional 200 feet of pay in separate fault blocks. A second well was spud in
January 2000 to test updip limits in one objective and further delineate a
deeper objective. Callon owns a 15% working interest in the well. It is
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operated by Murphy, which owns a 60% working interest, with the remaining
working interest being owned by British-Borneo Petroleum, Inc.
Entrada, Garden Banks 782/826/827
The test well, which will be drilled to a true vertical depth of 15,500 feet,
will be located in 4,690 feet of water and is scheduled to be spud during the
second quarter. The Company owns a 20 percent working interest and Vastar
Resources, Inc. is the operator.
GULF OF MEXICO SHELF
South Marsh Island Block 261 #1
The initial well was drilled to 8,000 feet and encountered 110 feet of net
natural gas pay in two sandstone formations between 5,400 feet and 5,800 feet.
The well tested at over 10 million cubic feet of natural gas ("MMcf") per day
from both the upper and lower perforations. Callon owns a 100% working interest
in this discovery and anticipates placing the well on production through
facilities on an adjacent block before the end of the second quarter of 2000.
South Marsh Island Block 261 #2
A second test well was spud in December 1999 and encountered 100 feet of net
natural gas in five pay sands. However, in January, the well blew out and had to
be plugged. The South Marsh Island Block 261 #3, a replacement well, is
currently drilling at an adjacent location and the company owns a 100% working
interest.
East Cameron Block 275
Drilled to a measured depth of 10, 746 feet, the company's test well encountered
net natural gas pay of 160 feet (TVD) in five intervals between 5,800 feet and
10,500 feet. The well tested at a combined rate of 18.1 million cubic feet of
natural gas equivalent ("MMcfe") per day from two zones. Callon owns a 100%
working interest in the well and anticipates placing the well on production
through facilities on an adjacent block at the beginning of the second quarter
2000.
Snapper, High Island Block A-494
The #C-1 well (Snapper prospect) reached a total depth of 8,800 feet and
encountered 207 feet of gross gas pay with 80 feet of net natural gas pay in the
objective Cris. S. sandstone formation. The well was brought on line in July
1999 and is currently producing 8.8 MMcf per day. Callon owns a 50% working
interest in the well and the operator, PetroQuest Energy, Inc. holds 42%.
RECENT DEVELOPMENTS
The Company had four exploration wells that were in progress at the end of 1999
and two wells that were drilled subsequent to year-end 1999. Four of these six
wells were determined to be non-commercial during the first quarter of 2000. In
the aggregate, the Company's net costs for the four unsuccessful wells were
approximately $12.1 million.
RECENT ACQUISITIONS
In December 1999, Callon purchased from Santos USA Corporation an additional 20%
working interest in the Boomslang deepwater discovery on Ewing Bank Block 994
for $7.3 million. This brought Callon's total working interest in the well to
55%.
In June 1999, the Company acquired various working interests in the Mobile Block
864 Area in which 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
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Company's interest in the area over a 39-month period. 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.
RISK FACTORS
VOLATILITY OF OIL AND GAS PRICES; MARKETABILITY OF PRODUCTION. The Company's
revenues, profitability and future growth and the carrying value of its oil and
gas properties are substantially dependent on prevailing prices of oil and gas.
The Company's ability to maintain or increase its borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent
upon oil and gas prices. Prices for oil and gas are subject to large
fluctuations in response to relatively minor changes in the supply of and demand
for oil and gas, market uncertainty and a variety of additional factors beyond
the control of the Company. Beginning in 1997 and continuing through early 1999,
the prices we received for production generally declined, especially for oil.
Oil prices have recently increased significantly, but remain volatile. Any
substantial and extended decline in the price of oil or gas would have an
adverse effect on the Company's carrying value of its proved reserves, borrowing
capacity, revenues, profitability and cash flows from operations.
Volatile oil and gas prices make it difficult to estimate the value of producing
properties for acquisition and often cause disruption in the market for oil and
gas producing properties, as buyers and sellers have difficulty agreeing on such
value. Price volatility also makes it difficult to budget for and project the
return on acquisitions and development and exploitation projects.
In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk.
RISKS OF EXPLORATION AND DEVELOPMENT
The major focus of the Company's operations over the next several years is
expected to be the exploration for and development of oil and gas properties,
primarily in federal and state waters in the Gulf of Mexico. Exploration and
drilling activities are generally considered to be of a higher risk than
acquisitions of producing oil and gas properties. Additionally, certain of the
Company's wells seek to discover deposits of oil and gas at deep formations and
have more risk than wells seeking to develop hydrocarbons from shallow
formations. No assurances can be made that the Company will discover oil and gas
in commercial quantities in its exploration and development operations.
Expenditure of a material amount of funds in exploration for oil and gas without
discovery of commercial quantities of reserves will have a material adverse
effect upon the Company.
OPERATING HAZARDS, OFFSHORE OPERATIONS AND UNINSURED RISKS. Callon's operations
are subject to risks inherent in the oil and gas industry, such as blowouts,
cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires,
pollution and other environmental risks. These risks could result in substantial
losses to the Company due to injury and loss of life, severe damage to and
destruction of property and equipment, pollution and other environmental damage
and suspension of operations. Moreover, a substantial portion of the Company's
operations are offshore and therefore are subject to a variety of operating
risks peculiar to the marine environment, such as hurricanes or other adverse
weather conditions, to more extensive governmental regulation, including
regulations that may, in certain circumstances, impose strict liability for
pollution
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damage, and to interruption or termination of operations by governmental
authorities based on environmental or other considerations.
The Company maintains insurance of various types to cover its operations,
including maritime employer's liability and comprehensive general liability.
Amounts in excess of base coverages are provided by primary and excess umbrella
liability policies with maximum limits of $50 million. In addition, the Company
maintains operator's extra expense coverage, which provides coverage for the
control of wells drilled and/or producing and redrilling expenses and pollution
coverage for wells out of control.
No assurances can be given that Callon will be able to maintain adequate
insurance in the future at rates the Company considers reasonable. The
occurrence of a significant event not fully insured or indemnified against could
materially and adversely affect the Company's financial condition and results of
operations.
ESTIMATES OF OIL AND GAS RESERVES
This document contains estimates of oil and gas reserves, and the future net
cash flows attributable to those reserves, prepared by Huddleston & Co., Inc.,
independent petroleum and geological engineers (the "Reserve Engineers"). There
are numerous uncertainties inherent in estimating quantities of proved reserves
and cash flows attributable to such reserves, including factors beyond the
control of the Company and the Reserve Engineers. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact manner. The accuracy of an estimate of quantities
of reserves, or of cash flows attributable to such reserves, is a function of
the available data, assumptions regarding future oil and gas prices and
expenditures for future development and exploitation activities, and of
engineering and geological interpretation and judgment. Additionally, reserves
and future cash flows may be subject to material downward or upward revisions,
based upon production history, development and exploitation activities and
prices of oil and gas. Actual future production, revenue, taxes, development
expenditures, operating expenses, quantities of recoverable reserves and the
value of cash flows from such reserves may vary significantly from the
assumptions and estimates set forth herein. In addition, reserve engineers may
make different estimates of reserves and cash flows based on the same available
data. In calculating reserves on a Mcfe basis, oil was converted to gas
equivalent at the ratio of six Mcf of gas to one barrel "(Bbl") of oil. While
this ratio approximates the energy equivalency of gas to oil on a Btu basis, it
may not represent the relative prices received by the Company on the sale of its
oil and gas production. The estimates include volumes of approximately 5.8 Bcf,
$12.1 million of future cash inflows and $10.7 million of discounted cash flows
attributable to a volumetric production payment.
The estimated quantities of proved reserves and the discounted present value of
future net cash flows attributable to estimated proved reserves set forth in
this document were prepared by the Reserve Engineers in accordance with the
rules of the Securities and Exchange Commission (the "Commission"), and are not
intended to represent the fair market value of such reserves.
OPERATIONS BY THIRD PARTIES
The Company does not operate all of its properties and has limited influence
over the operations of some of these properties, particularly the deepwater
projects. This lack of control could result in the operator initiating
exploration or development activities on a faster or slower pace than the
Company prefers. If the operator proposes to expand drilling or development
projects greater than the Company has funds for, the Company may be unable to
participate in the project or share in the revenues. Also if the operator
refuses to initiate a project, the Company may be unable to pursue the project,
which could reduce the value of the property.
DEEPWATER DRILLING AND OPERATIONS
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Drilling operations in the deepwater area are by their nature more difficult and
costly than drilling operations in shallower water. Deepwater exploration
requires the application of more advanced drilling technologies, involving a
higher risk of technological failure and usually resulting in significantly
higher drilling costs. Deepwater 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 deepwater area, the time required to commence production following a
discovery is much longer than in shallow waters and on-shore. All of the
Company's deepwater discoveries and prospects will require the construction of
expensive production facilities and pipelines prior to the beginning of
production. The costs and timing of the construction of these facilities cannot
be estimated with certainty, and the accuracy of such estimates will be affected
by a number of factors beyond our control, including decisions made by the
operators of our deepwater 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 the deepwater prospects and the discounted
present value of reserves attributable to those prospects.
ABILITY TO REPLACE RESERVES
The Company's future success depends upon its ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable. As is
generally the case in the Gulf Coast region, many of the Company's producing
properties are characterized by a high initial production rate, followed by a
steep decline in production. As a result, the Company must locate and develop or
acquire new oil and gas reserves to replace those being depleted by production.
Without successful exploration or acquisition activities, the Company's reserves
and revenues will decline rapidly. No assurances can be given that the Company
will be able to find and develop or acquire additional reserves at an acceptable
cost.
The exploration for oil and gas requires the expenditure of substantial amounts
of capital, and there can be no assurances that commercial quantities of oil or
gas will be discovered as a result of such activities. The Company's current
capital budget includes drilling 2 gross (.3 net) development wells and 13 gross
(5.2 net) exploratory wells through fiscal 2000. The estimated cost, net to the
Company, to drill and complete these wells is approximately $75 million with dry
hole costs of approximately $36 million. The drilling of several unsuccessful
wells could have a material adverse effect on the Company. In addition, the
successful acquisition of producing properties requires an assessment of
recoverable reserves, future oil and gas prices and operating costs, potential
environmental and other liabilities and other factors. Such assessments are
necessarily inexact and their accuracy inherently uncertain. In addition, no
assurances can be given that the Company's exploitation and development
activities will result in any increases in reserves. The Company's operations
may be curtailed, delayed or canceled as a result of lack of adequate capital
and other factors, such as title problems, weather, compliance with governmental
regulations or price controls, mechanical difficulties or shortages or delays in
the delivery of equipment. In addition, the costs of exploration and development
may materially exceed initial estimates.
SUBSTANTIAL CAPITAL REQUIREMENTS
The Company makes, and will continue to make, substantial capital expenditures
for the exploitation, exploration, acquisition and production of oil and gas
reserves. Historically, the Company has financed these expenditures primarily
with cash generated by operations, proceeds from bank borrowings and issuance of
debt and equity securities. The Company's total capital expenditure forecast for
2000 is approximately $85 million, and could be reduced depending on the success
of the Company's drilling activities. The Company makes unsolicited offers for
the acquisition of oil and gas properties in the normal course of business. In
the event that any such offers are accepted, the amount or composition of the
Company's capital expenditure budget could be revised significantly.
If revenues or the Company's borrowing base decrease as a result of lower oil
and gas prices, lack of drilling success, operating difficulties or declines in
reserves, the Company may have limited ability to repay debt and to expend the
capital necessary to undertake or complete future drilling programs. There
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can be no assurance that additional debt or equity financing or cash generated
by operations will be available to meet these requirements.
HEDGING OF PRODUCTION
Part of the Company's business strategy is to reduce its exposure to the
volatility of oil and gas prices by hedging a portion of its production. See
Item 7A. "Quantitative and Qualitative Disclosures About Market Risks." In a
typical hedge transaction, the Company will have the right to receive from the
counterparts to the hedge, the excess of the fixed price specified in the hedge
over a floating price based on a market index, multiplied by the quantity
hedged. If the floating price exceeds the fixed price, the Company is required
to pay the counterparts this difference multiplied by the quantity hedged. The
Company is required to pay the difference between the floating price and the
fixed price (when the floating price exceeds the fixed price) regardless of
whether the Company has sufficient production to cover the quantities specified
in the hedge. Significant reductions in production at times when the floating
price exceeds the fixed price could require the Company to make payments under
the hedge agreements even though such payments are not offset by sales of
production. Hedging will also prevent the Company from receiving the full
advantage of increases in oil or gas prices above the fixed amount specified in
the hedge. As of December 31, 1999, the Company had open collar contracts with
third parties whereby minimum floor prices and maximum ceiling prices are
contracted and applied to related contract volumes. These agreements in effect
for 2000 are for average gas volumes of 231,250 Mcf per month beginning in
February 2000 through September, 2000 at (on a weighted average) a ceiling price
of $2.80 and floor price of $2.56. The Company had no open oil hedging contracts
at December 31, 1999.
COMPETITION
The Company operates in the highly competitive areas of oil and gas exploration,
development and production. The availability of funds and information relating
to a property, the standards established by the Company for the minimum
projected return on investment, the availability of alternate fuel sources and
the intermediate transportation of gas are factors which affect the Company's
ability to compete in the marketplace. The Company's competitors include major
integrated oil companies, substantial independent energy companies, affiliates
of major interstate and intrastate pipelines and national and local gas
gatherers, many of which possess greater financial and other resources than the
Company.
ENVIRONMENTAL AND OTHER REGULATIONS
The Company's operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition
of a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells, and impose substantial liabilities
for pollution resulting from the Company's operations. Moreover, the recent
trend toward stricter standards in environmental legislation and regulation is
likely to continue. The enactment of stricter legislation or the adoption of
stricter regulation could have a significant impact on the operating costs of
the Company, as well as on the oil and gas industry in general.
The Company's operations could result in liability for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. Moreover, the Company could be
liable for environmental damages caused by previous property owners. As a
result, substantial liabilities to third parties or governmental entities may be
incurred; the payment of which could have a material adverse effect on the
Company's financial condition and results of operations. The Company maintains
insurance coverage for its operations, including limited coverage for sudden and
accidental environmental damages, but does not believe that insurance coverage
for environmental damages that occur over time is available at a reasonable
cost. Moreover, the Company does not believe that
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insurance coverage for the full potential liability that could be caused by
sudden and accidental environmental damages is available at a reasonable cost.
Accordingly, the Company may be subject to liability or may lose the privilege
to continue exploration or production activities upon substantial portions of
its properties in the event of certain environmental damages.
The Oil Pollution Act of 1990 imposes a variety of regulations on "responsible
parties" related to the prevention of oil spills. The implementation of new, or
the modification of existing, environmental laws or regulations, including
regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a
material adverse impact on the Company.
MARKETS
Callon's ability to market oil and gas from the Company's wells depends upon
numerous factors beyond the Company's control, including the extent of domestic
production and imports of oil and gas, the proximity of the gas production to
gas pipelines, the availability of capacity in such pipelines, the demand for
oil and gas by utilities and other end users, the availability of alternative
fuel sources, the effects of inclement weather, and state and federal regulation
of oil and gas production and federal regulation of gas sold or transported in
interstate commerce. No assurance can be given that Callon will be able to
market all of the oil or gas produced by the Company or that favorable prices
can be obtained for the oil and gas Callon produces.
In view of the many uncertainties affecting the supply and demand for oil, gas
and refined petroleum products, the Company is unable to predict future oil and
gas prices and demand or the overall effect such prices and demand will have on
the Company. Callon does not believe that the loss of any of the Company's oil
purchasers would have a material adverse effect on the Company's operations.
Additionally, since substantially all of the Company's gas sales are on the spot
market, the loss of one or more gas purchasers should not materially and
adversely affect the Company's financial condition. The marketing of oil and gas
by Callon can be affected by a number of factors, which are beyond the Company's
control, the exact effects of which cannot be accurately predicted.
CORPORATE OFFICES
The Company's headquarters are located in Natchez, Mississippi, in approximately
51,500 square feet of owned space. The Company also maintains owned or leased
field offices in the area of the major fields in which it operates properties or
has a significant interest. Replacement of any of the Company's leased offices
would not result in material expenditures by the Company as alternative
locations to its leased space are anticipated to be readily available.
EMPLOYEES
The Company had 94 employees as of December 31, 1999, none of who are currently
represented by a union. The Company considers itself to have good relations with
its employees. The Company employs six petroleum engineers and five petroleum
geoscientists.
FEDERAL REGULATIONS
SALES OF NATURAL GAS. Effective January 1, 1993, the Natural Gas Wellhead
Decontrol Act deregulated prices for all "first sales" of natural gas. Thus, all
sales of gas by the Company may be made at market prices, subject to applicable
contract provisions.
TRANSPORTATION OF NATURAL GAS. The rates, terms and conditions applicable to the
interstate transportation of natural gas by pipelines are regulated by the
Federal Energy Regulatory Commission ("FERC") under the
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Natural Gas Act ("NGA"), as well as under section 311 of the Natural Gas Policy
Act ("NGPA"). Since 1985, the FERC has implemented regulations intended to make
natural gas transportation more accessible to gas buyers and sellers on an
open-access, non-discriminatory basis.
The FERC has announced several important transportation-related policy
statements and rule changes, including a statement of policy and final rule
issued February 25, 2000 concerning alternatives to its traditional
cost-of-service rate-making methodology to establish the rates interstate
pipelines may charge for their services. The final rule revises FERC's pricing
policy and current regulatory framework to improve the efficiency of the market
and further enhance competition in natural gas markets.
With respect to the transportation of natural gas on or across the Outer
Continental Shelf ("OCS"), the FERC requires, as part of its regulation under
the Outer Continental Shelf Lands Act, that all pipelines provide open and
non-discriminatory access to both owner and non-owner shippers. Although to date
the FERC has imposed light-handed regulation on off-shore facilities that meet
its traditional test of gathering status, it has the authority to exercise
jurisdiction under the Outer Continental Shelf Lands Act ("OCSLA") over
gathering facilities, if necessary, to permit non-discriminatory access to
service. For those facilities transporting natural gas across the OCS that are
not considered to be gathering facilities, the rates, terms, and conditions
applicable to this transportation are regulated by FERC under the NGA and NGPA,
as well as the OCSLA.
SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil and condensate can be
made by the Company at market prices not subject at this time to price controls.
The price that the Company receives from the sale of these products will be
affected by the cost of transporting the products to market. The rates, terms,
and conditions applicable to the interstate transportation of oil and related
products by pipelines are regulated by the FERC under the Interstate Commerce
Act. As required by the Energy Policy Act of 1992, the FERC has revised its
regulations governing the rates that may be charged by oil pipelines. The new
rules, which were effective January 1, 1995, provide a simplified, generally
applicable method of regulating such rates by use of an index for setting rate
ceilings. The FERC will also, under defined circumstances, permit alternative
ratemaking methodologies for interstate oil pipelines such as the use of cost of
service rates, settlement rates, and market-based rates. Market-based rates will
be permitted to the extent the pipeline can demonstrate that it lacks
significant market power in the market in which it proposes to charge
market-based rates. The cumulative effect that these rules may have on moving
the Company's production to market cannot yet be determined.
With respect to the transportation of oil and condensate on or across the OCS,
the FERC requires, as part of its regulation under the OCSLA, that all pipelines
provide open and non-discriminatory access to both owner and non-owner shippers.
Accordingly, the FERC has the authority to exercise jurisdiction under the
OCSLA, if necessary, to permit non-discriminatory access to service.
LEGISLATIVE PROPOSALS. In the past, Congress has been very active in the area of
natural gas regulation. There are legislative proposals pending in Congress and
in various state legislatures which, if enacted, could significantly affect the
petroleum industry. At the present time it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on the Company's
operations.
FEDERAL, STATE OR INDIAN LEASES. In the event the Company conducts operations on
federal, state or Indian oil and gas leases, such operations must comply with
numerous regulatory restrictions, including various nondiscrimination statutes,
royalty and related valuation requirements, and certain of such operations must
be conducted pursuant to certain on-site security regulations and other
appropriate permits issued by the Bureau of Land Management ("BLM") or Minerals
Management Service ("MMS") or other appropriate federal or state agencies.
10
<PAGE> 11
The Company's OCS leases in federal waters are administered by the MMS and
require compliance with detailed MMS regulations and orders. The MMS has
promulgated regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. Under
certain circumstances, the MMS may require and Company operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition and
operations. On March 15, 2000, the MMS issued a final rule effective June 1,
2000 which amends its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. Among other matters, this
rule amends the valuation procedure for the sale of federal royalty oil by
eliminating posted prices as a measure of value and relying instead on arm's
length sales prices and spot market prices as market value indicators. Because
the Company sells its production in the spot market and therefore pays royalties
on production from federal leases, it is not anticipated that this final rule
will have any substantial impact on the Company.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect
ownership of any interest in federal onshore oil and gas leases by a foreign
citizen of a country that denies "similar or like privileges" to citizens of the
United States. Such restrictions on citizens of a "non-reciprocal" country
include ownership or holding or controlling stock in a corporation that holds a
federal onshore oil and gas lease. If this restriction is violated, the
corporation's lease can be canceled in a proceeding instituted by the United
States Attorney General. Although the regulations of the BLM (which administers
the Mineral Act) provide for agency designations of non-reciprocal countries,
there are presently no such designations in effect. The Company owns interests
in numerous federal onshore oil and gas leases. It is possible that holders of
equity interests in the Company may be citizens of foreign countries, which at
some time in the future might be determined to be non-reciprocal under the
Mineral Act.
STATE REGULATIONS
Most states regulate the production and sale of oil and natural gas, including
requirements for obtaining drilling permits, the method of developing new
fields, the spacing and operation of wells and the prevention of waste of oil
and gas resources. The rate of production may be regulated and the maximum daily
production allowable from both oil and gas wells may be established on a market
demand or conservation basis or both.
The Company may enter into agreements relating to the construction or operation
of a pipeline system for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such
operations may, in certain instances, be subject to the jurisdiction of such
state's administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates which the Company could charge
for gas, the transportation of gas, and the costs of construction and operation
of such pipeline would be impacted by the rules and regulations governing such
matters, if any, of such administrative authority. Further, such a pipeline
system would be subject to various state and/or federal pipeline safety
regulations and requirements, including those of, among others, the Department
of Transportation. Such regulations can increase the cost of planning,
designing, installation and operation of such facilities. The impact of such
pipeline safety regulations would not be any more adverse to the Company than it
would be to other similar owners or operators of such pipeline facilities.
ENVIRONMENTAL REGULATIONS
11
<PAGE> 12
GENERAL. The Company's activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. Although no assurances can be made, the Company believes that, absent
the occurrence of an extraordinary event, compliance with existing federal,
state and local laws, rules and regulations regulating the release of materials
in the environment or otherwise relating to the protection of the environment
will not have a material effect upon the capital expenditures, earnings or the
competitive position of the Company with respect to its existing assets and
operations. The Company cannot predict what effect additional regulation or
legislation, enforcement policies thereunder, and claims for damages to
property, employees, other persons and the environment resulting from the
Company's operations could have on its activities.
Activities of the Company with respect to natural gas facilities, including the
operation and construction of pipelines, plants and other facilities for
transporting, processing, treating or storing natural gas and other products,
are subject to stringent environmental regulation by state and federal
authorities including the United States Environmental Protection Agency ("EPA").
Such regulation can increase the cost of planning, designing, installation and
operation of such facilities. In most instances, the regulatory requirements
relate to water and air pollution control measures. Although the Company
believes that compliance with environmental regulations will not have a material
adverse effect on it, risks of substantial costs and liabilities are inherent in
oil and gas production operations, and there can be no assurance that
significant costs and liabilities will not be incurred. Moreover, it is possible
that other developments, such as stricter environmental laws and regulations,
and claims for damages to property or persons resulting from oil and gas
production, would result in substantial costs and liabilities to the Company.
SOLID AND HAZARDOUS WASTE. The Company owns or leases numerous properties that
have been used for production of oil and gas for many years. Although the
Company has utilized operating and disposal practices standard in the industry
at the time, hydrocarbons or other solid wastes may have been disposed or
released on or under these properties. In addition, many of these properties
have been operated by third parties. The Company had no control over such
entities' treatment of hydrocarbons or other solid wastes and the manner in
which such substances may have been disposed or released. State and federal laws
applicable to oil and gas wastes and properties have gradually become stricter
over time. Under these new laws, the Company could be required to remove or
remediate previously disposed wastes (including wastes disposed or released by
prior owners or operators) or property contamination (including groundwater
contamination by prior owners or operators) or to perform remedial plugging
operations to prevent future contamination.
The Company generates wastes, including hazardous wastes, that are subject to
the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA has limited the disposal options for certain hazardous wastes
and is considering the adoption of stricter disposal standards for nonhazardous
wastes. Furthermore, it is possible that certain wastes currently exempt from
treatment as "hazardous wastes" generated by the Company's oil and gas
operations may in the future be designated as "hazardous wastes" under RCRA or
other applicable statutes, and therefore be subject to more rigorous and costly
disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on certain classes of
persons with respect to the release of a "hazardous substance" into the
environment. These persons include the owner and operator of a site and persons
that disposed or arranged for the disposal of the hazardous substances found at
a site. CERCLA also authorizes the EPA and, in some cases, third parties to take
actions in response to threats to the public health or the environment and to
seek to recover from the responsible classes of persons the costs of such
action. Neither the Company nor its predecessors has been designated as a
potentially responsible party by the EPA under CERCLA with respect to any such
site.
12
<PAGE> 13
OIL POLLUTION ACT. The Oil Pollution Act of 1990 (the "OPA") and regulations
thereunder impose a variety of regulations on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in United States waters. A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which an offshore facility is located. The OPA assigns liability to each
responsible party for oil removal costs and a variety of public and private
damages. While liability limits apply in some circumstances, a party cannot take
advantage of liability limits if the spill was caused by gross negligence or
willful misconduct or resulted from violation of a federal safety, construction
or operating regulation. If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. Few defenses exist
to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain amendments to the OPA that were enacted in 1996 require owners
and operators of offshore facilities that have a worst case oil spill potential
of more than 1,000 barrels to demonstrate financial responsibility in amounts
ranging from $10 million in specified state waters and $35 million in federal
OCS waters, with higher amounts, up to $150 million based upon worst case
oil-spill discharge volume calculations. The Company believes that it currently
has established adequate proof of financial responsibility for its offshore
facilities.
AIR EMISSIONS. The operations of the Company are subject to local, state and
federal regulations for the control of emissions from sources of air pollution.
Administrative enforcement actions for failure to comply strictly with air
regulations or permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could require the Company to forego construction or operation of certain air
emission sources, although the Company believes that in such case it would have
enough permitted or permittable capacity to continue its operations without a
material adverse effect on any particular producing field.
OSHA. The Company is subject to the requirements of the Federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the Federal Superfund Amendment and Reauthorization Act and similar state
statutes require the Company to organize and/or disclose information about
hazardous materials used or produced in its operations. Certain of this
information must be provided to employees, state and local governmental
authorities and local citizens.
Management believes that the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements would not have a material adverse impact on the Company.
ITEM 2. PROPERTIES
The Company is engaged in the acquisition, development, exploitation and
exploration of oil and gas properties and natural gas transmission and provides
oil and gas property management services for other investors. The Company's
properties are concentrated offshore in the Gulf of Mexico and onshore,
primarily, in Louisiana and Alabama. As of December 31, 1999, the Company's
estimated proved reserves totaled 23.8 million barrels of oil ("MBbl") and 116.4
Bcf of natural gas, with a pre-tax present value, discounted at 10%, of the
estimated future net revenues based on constant prices in effect at year-end
("Discounted Cash Flow") of $296.5 million. Gas constitutes approximately 45% of
the Company's total estimated proved reserves and approximately 26% of the
Company's reserves are proved producing reserves.
SIGNIFICANT PROPERTIES
13
<PAGE> 14
The following table shows discounted cash flows and estimated net proved oil and
gas reserves by major field for the Company's ten largest fields and for all
other properties combined at December 31, 1999.
<TABLE>
<CAPTION>
PERCENT ESTIMATED NET PROVED
DISCOUNTED TOTAL ------------------------------------
PROVED RESERVES BY PRIMARY CASH FLOW DISCOUNTED RESERVES RESERVES RESERVES
FOCUS AREA: OPERATOR(S) ($000)(a)(b) CASH FLOW (MBBLS)(b) (MMcf)(b) (MMcfe)(b)
- ------------------ ----------- ------------ --------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C>
GULF OF MEXICO DEEPWATER:
Ewing Bank Block 994
"Boomslang" Murphy $ 53,507 18.1% 7,230 13,015 56,395
Mississippi Canyon
538/582 "Medusa" Murphy 65,302 22.0% 8,835 8,764 61,774
Garden Banks Block 341
"Habanero" Shell 66,993 22.6% 6,393 12,547 50,902
-------- ----- ------ ------- -------
TOTAL DEEPWATER 185,802 62.7% 22,458 34,326 169,071
GULF OF MEXICO SHELF:
Mobile Block 864 Area Callon 55,545 18.7% 0 48,897 48,897
South Marsh Island 261 Callon 16,070 5.4% 32 10,768 10,962
East Cameron 275 Callon 4,865 1.6% 27 5,325 5,485
Main Pass Block 26/SL Callon 5,775 2.0% 123 3,024 3,761
15827
High Island Block A-494
"Snapper" PetroQuest 3,217 1.1% 0 2,828 2,828
Eugene Island Block 335 Murphy 3,212 1.1% 48 1,574 1,862
Other Callon 1,282 0.4% 69 3,114 3,527
-------- ----- ------ ------- -------
TOTAL SHELF 89,966 30.3% 299 75,530 77,322
ONSHORE: -------- ----- ------ ------- -------
Big Escambia Creek Exxon 7,785 2.6% 657 1,703 5,647
Other Various 12,960 4.4% 420 4,876 7,401
-------- ----- ------ ------- -------
TOTAL ONSHORE 20,745 7.0% 1,077 6,579 13,048
--------
TOTAL $296,513 100.0% 23,834 116,435 259,441
======== ===== ====== ======= =======
</TABLE>
(a) Represents the present value of future net cash flows before deduction of
federal income taxes, discounted at 10%, attributable to estimated proved
reserves as of December 31, 1999, as set forth in the Company's independent
reserve reports prepared by Huddleston & Co., Inc. of Houston, Texas.
(b) The estimates include volumes of approximately 5.8 Bcf, $12.1 million of
future cash inflows and $10.7 million of discounted cash flows attributable
to a volumetric production payment.
GULF OF MEXICO DEEPWATER
Boomslang, Ewing Bank Block 994
14
<PAGE> 15
Located in 900 feet of water, the Boomslang prospect was drilled to a total
depth of 12,955 feet and encountered 185 net feet of oil pay in three separate
zones. In December 1999, Callon purchased from Santos USA Corporation an
additional 20% working interest in the Boomslang deepwater discovery on Ewing
Bank Block 994 for $7.3 million. This brought Callon's total working interest in
the well to 55%. Estimated net proved reserves at December 31, 1999 were 7.2
million barrels of oil and 13.0 Bcf of natural gas with a discounted cash flow
of $53.5 million.
Prior to designing production facilities for Boomslang the Company plans to
drill the Sidewinder prospect, located immediately to the southeast of Boomslang
on Ewing Bank Block 995 and Green Canyon Blocks 24 and 25. Callon owns a 15%
working interest in these leases.
Medusa, Mississippi Canyon Block 538/582
The initial well encountered two intervals with over 120 feet of total pay after
being drilling to a measured depth of 16,241 feet. The test well encountered 59
true vertical feet of pay in the T1 objective in Fault Block A and 61 true
vertical feet of pay in the T4 sand. A sidetrack well, testing the extent of the
discovery, encountered 110 true vertical feet of pay in the T1 objective sand in
Fault Block B. An additional sidetrack well was drilled to test the downdip
limits of the T1 pay sand in Fault Block B and encountered 90 feet (True
Vertical Depth) of oil pay. A delineation well was spud in January and is
designed to test the updip limits of the T1 pay sand in Fault Block A. This
latest well will drill deeper to further delineate the T4 objective, which was
discovered by the original well. The Prospect lies in approximately 2,100 feet
of water and the company owns a 15% working interest with Murphy, the operator
owning 60% and British-Borneo Petroleum, Inc. owning the remaining 25%. This was
Callon's third consecutive deepwater discovery. Estimated net proved reserves at
December 31, 1999 were 8.8 million barrels of oil and 8.8 Bcf of natural gas
with a discounted cash flow of $65.3 million.
Habanero, Garden Banks Block 341
During February 1999 the initial test well on the Company's Habanero prospect
encountered over 200 feet of net pay. Located in 2,000 feet of water, the well
was drilled to a measured depth of 21,158 feet. This discovery was the second
deepwater success for Callon. Callon owns an 11.25% working interest in the
well. It is operated by Shell Deepwater Development Inc., which owns a 55%
working interest, with the remaining working interest being owned by Murphy.
Estimated net proved reserves at December 31, 1999 were 6.4 million barrels of
oil and 12.5 Bcf of natural gas with a discounted cash flow of $67.0 million.
GULF OF MEXICO SHELF
Mobile Block 864 Area
The Mobile Block 864 Area is located offshore Alabama in the federal waters of
the OCS. The Company consummated five acquisitions in this area for a total of
$63.8 million. In total, the Company has acquired an average 81.6% working
interest in seven blocks, a 66.4% working interest in the Mobile Block 864 Area
unit and the unit production facilities, and a 100% working interest in three
producing wells. The Company was appointed operator of the Mobile Block 864 unit
and three other wells. Estimated net proved reserves at December 31, 1999 were
48.9 Bcf and a discounted cash flow value of $55.5 million. Net average daily
production during 1999 was 15.2 MMcf per day.
South Marsh Island Block 261 #1
The initial well was drilled to 8,000 feet and encountered 110 feet of net
natural gas pay in two sandstone formations between 5,400 feet and 5,800 feet.
The Company separately flow-tested each pay zone. The upper completion tested at
10.3 million cubic feet of natural gas per day (MMcf/d) from perforations at
5,410 feet through 5,450 feet on a 25/64-inch choke with flowing tubing pressure
of 2,852 pounds per
15
<PAGE> 16
square inch (Psi). The lower completion tested at 10.1 MMcf/d from perforations
at 5,678 feet through 5,714 feet on a 24/64-inch choke with flowing tubing
pressure of 3,004 Psi. The single selective completion will allow production
from either of the two pay zones through 3 1/2-inch production tubing. Callon
owns a 100% working interest in this discovery and anticipates placing the well
on production through facilities on an adjacent block before the end of the
second quarter of 2000. Estimated net proved reserves at December 31, 1999 were
11.0 Bcfe and a discounted cash flow value of $16.1 million.
East Cameron Block 275
Drilled to a measured depth of 10,746 feet, the Company's test well encountered
net natural gas pay of 160 feet (TVD) in five intervals between 5,800 feet and
10,500 feet. The well tested at a combined rate of 18.1 million cubic feet of
natural gas equivalent (MMcfe) per day from two zones. From lower perforations
between 10,461 feet through 10,482 feet the well tested at 4.6 million cubic
feet of natural gas (MMcf) and 240 barrels of condensate (Bc) per day on a
20/64-inch choke with flowing tubing pressure of 2,605 pounds per square inch
(Psi). It tested at 8.9 MMcf and 528 Bc per day from upper perforations between
10,384 feet and 10,418 feet on a 22/64-inch choke with flowing tubing pressure
of 3,315 Psi. The well is scheduled to begin production at the beginning of the
second quarter 2000. Callon owns a 100% working interest in the well. Estimated
net proved reserves at December 31, 1999 were 5.5 Bcfe and a discounted cash
flow value of $4.9 million.
Main Pass 26 / SL 15827 #1
The Company negotiated a farm-in agreement in 1998 for a 97% working interest
after identifying a prospect on the Main Pass 26 Block based upon a 1996 seismic
survey completed by the Company. In August 1998 the State Lease 15827 #1 well
was drilled to a depth of 10,450 feet. The well encountered 45 feet of net
natural gas pay over a gross interval from 10,084 feet to 10,218 feet. The
discovery is located approximately 2.6 miles north of Callon's existing
facilities at Main Pass Block 32. The well was tied-in and placed on production
in February 1999. Estimated net proved reserves at December 31, 1999 were 3.0
Bcf of natural gas and 123 MBbls of condensate with a discounted cash flow of
$5.8 million.
Snapper, High Island Block A-494
In February 1999, the #C-1 well reached a total depth of 8,800 and encountered
207 feet of gross gas pay with 80 feet of net natural gas pay in the objective
Cris. S. sandstone formation. The well was brought on line in July 1999 and is
currently producing 8.8 million cubic feet of natural gas per day (MMcf/d).
Callon owns a 50% working interest in the well and the operator, PetroQuest
Energy, Inc. holds 42%. Estimated net proved reserves at December 31, 1999 were
2.8 Bcfe with a discounted cash flow value of $3.2 million.
Eugene Island 335
Three wells were drilled on Eugene Island Block 335 during 1997. The wells
encountered a total of six pay sands, which with fault separations, form eight
productive reservoirs. Production facility installation was completed during the
fourth quarter of 1998. Production commenced during the first quarter of 1999
and the wells are currently producing at a rate of 16.3 MMcf and 643 Bbls per
day. Callon owns a 20% working interest in the wells. Estimated net proved
reserves at December 31, 1999 were 48 MBbls of oil and 1.6 Bcf of natural gas.
ONSHORE
Big Escambia Creek
The Company owns an average working interest of 6.0% (6.6% net revenue
interest), subject to a 10% reduction after payout, in nine wells and a 2.9%
average royalty interest in another six wells. The gross
16
<PAGE> 17
average daily production for these wells during December 1999 was 2.6 MBbls of
condensate, 1.1 MBbls of natural gas liquids, 6.7 MMcf of residue natural gas
and 312 long tons of sulfur. These wells are producing from the Smackover
formation at depths ranging from 15,100 to 15,600 feet.
OIL AND GAS RESERVES
The following table sets forth certain information about the estimated proved
reserves of the Company as of the dates set forth below.
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
-----------------------------------
1999(a) 1998 1997
------- ---- ----
<S> <C> <C> <C>
(IN THOUSANDS)
Proved developed:
Oil (Bbls) 1,376 2,079 2,976
Gas (Mcf) 82,109 76,895 88,010
Proved undeveloped:
Oil (Bbls) 22,458 4,819 426
Gas (Mcf) 34,326 11,135 728
Total proved:
Oil (Bbls) 23,834 6,898 3,402
Gas (Mcf) 116,435 88,030 88,738
Estimated pre-tax future net cash flows $528,659 $152,552 $209,264
======== ======== ========
Discounted cash flows $296,513 $99,751 $136,448
======== ======= ========
</TABLE>
(a) The estimates include volumes of approximately 5.8 Bcf, $12.1 million of
future cash inflows and $10.7 million of discounted cash flows attributable to a
volumetric production payment.
The Company's independent Reserve Engineers prepared the estimates of the proved
reserves and the future net cash flows (and present value thereof) attributable
to such proved reserves. Reserves were estimated using oil and gas prices and
production and development costs in effect on December 31 of each such year,
without escalation, and were otherwise prepared in accordance with the
Commission regulations regarding disclosure of oil and gas reserve information.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond the control of the Company and the
reserve engineers. Reserve engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
manner, and the accuracy of any reserve or cash flow estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Estimates by different engineers often vary, sometimes
significantly. In addition, physical factors, such as the results of drilling,
testing and production subsequent to the date of an estimate, as well as
economic factors, such as an increase or decrease in product prices that renders
production of such reserves more or less economic, may justify revision of such
estimates. Accordingly, reserve estimates are different from the quantities of
oil and gas that are ultimately recovered.
The Company has not filed any reports with other federal agencies, which contain
an estimate of total proved net oil and gas reserves.
17
<PAGE> 18
PRODUCTIVE WELLS
The following table sets forth the wells drilled and completed by the Company
during the periods indicated. All such wells were drilled in the continental
United States including federal and state waters in the Gulf of Mexico.
<TABLE>
<CAPTION>
Years Ended December 31,
--------------------------------------------------------
1999 1998 1997
-------------- -------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Development:
Oil -- -- 2 .40 -- --
Gas -- -- -- -- 1 1.00
Non-productive -- -- -- -- -- --
------ ------ ------ ------ ---- -----
-- -- 2 .40 1 1.00
====== ====== ====== ====== ==== =====
Exploration:
Oil 2 0.26 1 .35 -- --
Gas 5 3.79 3 2.14 2 1.20
Non-productive 2 1.20 2 1.25 6 1.91
------ ------ ------ ------ ---- ----
Total 9 5.25 6 3.74 8 3.11
====== ====== ====== ====== ==== ====
</TABLE>
The Company owned working and royalty interests in approximately 261 gross (8.2
net) producing oil and 298 gross (27.6 net) producing gas wells as of December
31, 1999. A well is categorized as an oil well or a natural gas well based upon
the ratio of oil to gas reserves on a Mcfe basis. However, substantially all of
the Company's wells produce both oil and gas. At December 31, 1999, the Company
had two exploratory gas wells and two exploratory oil wells in progress.
LEASEHOLD ACREAGE
The following table shows the approximate developed and undeveloped (gross and
net) leasehold acreage of the Company as of December 31, 1999.
18
<PAGE> 19
<TABLE>
<CAPTION>
LEASEHOLD ACREAGE
----------------------------------------
DEVELOPED UNDEVELOPED
----------------- ----------------
LOCATION GROSS NET GROSS NET
-------- ----- --- ----- ---
<S> <C> <C> <C> <C>
Alabama 12,813 12,685 64 64
Louisiana 10,462 9,376 11,016 6,928
Other States 888 416 1,478 1,169
Federal Waters 118,331 84,874 333,869 84,145
------- ------- ------- ------
Total 142,494 107,351 346,427 92,306
======= ======= ======= ======
</TABLE>
As of December 31, 1999, the Company owned various royalty and overriding
royalty interests in 1,336 net developed acres and 6,862 undeveloped acres. In
addition, the Company owned 5,464 developed and 134,536 undeveloped mineral
acres.
MAJOR CUSTOMERS
For the year ended December 31, 1999, Dynegy Marketing & Trade, Adams Resources
Marketing, Ltd., and Columbia Energy Services 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, MP164/165, MB864, EI 335, HI A494, and MB952/955
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.
TITLE TO PROPERTIES
The Company believes that the title to its oil and gas properties is good and
defensible in accordance with standards generally accepted in the oil and gas
industry, subject to such exceptions which, in the opinion of the Company, are
not so material as to detract substantially from the use or value of such
properties. The Company's properties are typically subject, in one degree or
another, to one or more of the following: royalties and other burdens and
obligations, express or implied, under oil and gas leases; overriding royalties
and other burdens created by the Company or its predecessors in title; a variety
of contractual obligations (including, in some cases, development obligations)
arising under operating agreements, farmout agreements, production sales
contracts and other agreements that may affect the properties or their titles;
back-ins and reversionary interests existing under purchase agreements and
leasehold assignments; liens that arise in the normal course of operations, such
as those for unpaid taxes, statutory liens securing obligations to unpaid
suppliers and contractors and contractual liens under operating agreements;
pooling, unitization and communitization agreements, declarations and orders;
and easements, restrictions, rights-of-way and other matters that commonly
affect property. To the extent that such burdens and obligations affect the
Company's rights to production revenues, they have been taken into account in
calculating the Company's net revenue interests and in estimating the size and
value of the Company's reserves. The Company believes that the burdens and
obligations affecting its properties are conventional in the industry for
properties of the kind owned by the Company.
ITEM 3. LEGAL PROCEEDINGS
19
<PAGE> 20
The Company is a defendant in various legal proceedings and claims, which arise
in the ordinary course of Callon's business. Callon does not believe the
ultimate resolution of any such actions will have a material affect on the
Company's financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth
quarter of 1999.
PART II.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Effective April 22, 1998, the Company's Common Stock began trading on the New
York Stock Exchange under the symbol "CPE". Prior to that time, the Company's
Common Stock was traded on the Nasdaq
20
<PAGE> 21
National Market System under the symbol "CLNP". The following table sets forth
the high and low sale prices per share as reported for the periods indicated.
Quarter Ended High Low
1998:
First quarter $17.125 $15.000
Second quarter 18.375 14.000
Third quarter 14.875 7.875
Fourth quarter 14.000 10.875
1999:
First quarter $11.875 $ 8.875
Second quarter 11.250 9.875
Third quarter 15.375 10.000
Fourth quarter 15.375 11.625
As of March 13, 2000, there were approximately 6,791 common stockholders of
record.
The Company has not paid dividends on the Common Stock and intends to retain its
cash flow from operations, net of preferred stock dividends, for the future
operation and development of its business. In addition, the Company's primary
credit facility and the terms of the Company's outstanding Subordinated Debt
restrict payments of dividends on its Common Stock.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth, as of the dates and for the periods indicated,
selected financial information for the Company. The financial information for
each of the five years in the period ended December 31, 1999 have been derived
from the audited Consolidated Financial Statements of the Company for such
periods. The information should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements and Notes thereto. The following
information is not necessarily indicative of future results for the Company.
21
<PAGE> 22
CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31,
----------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales $ 37,140 $ 35,624 $ 42,130 $ 25,764 $ 23,210
Interest and other 1,853 2,094 1,508 946 627
-------- -------- -------- -------- --------
Total revenues 38,993 37,718 43,638 26,710 23,837
-------- -------- -------- -------- --------
Costs and expenses:
Lease operating expenses 7,536 7,817 8,123 7,562 6,732
Depreciation, depletion and amortization 16,727 19,284 16,488 9,832 10,376
General and administrative 4,575 5,285 4,433 3,495 3,880
Interest 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 35,013 83,572 31,001 21,202 22,782
-------- -------- -------- -------- --------
Income (loss) from operations 3,980 (45,854) 12,637 5,508 1,055
Income tax expense (benefit) 1,353 (15,100) 4,200 50 --
-------- -------- -------- -------- --------
Net income (loss) 2,627 (30,754) 8,437 5,458 1,055
Preferred stock dividends 2,497 2,779 2,795 2,795 256
-------- -------- -------- -------- --------
Net income (loss) available to common shares $ 130 $(33,533) $ 5,642 $ 2,663 $ 799
======== ======== ======== ======== ========
Net income (loss) per common share:
Basic $ .01 $ (4.17) $ .91 $ .46 $ .14
Diluted $ .01 $ (4.17) $ .88 $ .45 $ .14
Shares used in computing net income (loss) per
common share:
Basic 8,976 8,034 6,194 5,835 5,755
Diluted 9,075 8,034 6,422 5,952 5,755
Balance Sheet Data (end of period):
Oil and gas properties, net $194,365 $141,905 $150,494 $ 82,489 $ 57,765
Total assets $259,877 $181,652 $190,421 $118,520 $ 83,867
Long-term debt, less current portion $100,250 $ 78,250 $ 60,250 $ 24,250 $ 100
Stockholders' equity $124,380 $ 84,484 $113,701 $ 77,864 $ 75,129
</TABLE>
- -------------
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the
Company's financial condition and results of operations. The Company's Financial
Statements and Notes thereto contain detailed information that should be
referred to in conjunction with the following discussion. See Item 8. "Financial
Statements and Supplementary Data."
GENERAL
22
<PAGE> 23
Callon Petroleum Company has been engaged in the exploration, development and
acquisition of oil and gas properties since 1950. The Company's revenues,
profitability and future growth and the carrying value of its oil and gas
properties are substantially dependent on prevailing prices of oil and gas and
its ability to find, develop and acquire additional oil and gas reserves that
are economically recoverable. The Company's ability to maintain or increase its
borrowing capacity and to obtain additional capital on attractive terms is also
influenced by oil and gas prices.
Proved oil and gas reserves increased significantly to 259 billion cubic feet of
natural gas equivalent (Bcfe). This represents an increase of 101% over previous
year-end 1998 proved reserves of 129 Bcfe. This increase in 1999 is primarily
due to results of drilling activity in the deepwater areas of the Gulf of
Mexico, along with drilling successes on the Outer Continental Shelf in the same
region. Proved Undeveloped Reserves increased 322% over 1998 amounts due
primarily to deepwater exploration successes at Habanero and Medusa together
with additional interests acquired in 1999 at Ewing Bank Block 994, which was
discovered in 1998. Development of these significant reserve additions will
require substantial capital.
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond the control of the
Company. These factors include weather conditions in the United States, the
condition of the United States economy, the actions of the Organization of
Petroleum Exporting Countries, governmental regulation, political stability in
the Middle East and elsewhere, the foreign supply of crude oil and natural gas,
the price of foreign imports and the availability of alternate fuel sources. Any
substantial and extended decline in the price of crude oil or natural gas would
have an adverse effect on the Company's carrying value of its proved reserves,
borrowing capacity, revenues, profitability and cash flows from operation. The
Company uses derivative financial instruments (see Note 6 and Item 7A.
"Quantitative and Qualitative Disclosures About Market Risks") for price
protection purposes on a limited amount of its future production and does not
use them for trading purposes. On a Mcfe basis, natural gas represents 89% of
the projected 2000 production and 45% of proved reserves at year-end.
Inflation has not had a material impact on the Company and is not expected to
have a material impact on the Company in the future.
YEAR 2000 COMPLIANCE
Callon, like all other enterprises that utilize computer technology, faced a
threat of business disruption from the Year 2000 issue. The Year 2000 issue
refers to the inability of computer and other information technology systems to
properly process date and time information, stemming from the outdated
programming practice of using two digits rather than four to represent the year
in a date. The consequence of the Year 2000 issue is that computer and embedded
processing systems are at risk of malfunctioning, particularly during the
transition from 1999 to 2000.
Total costs incurred for consultants, software and hardware applications for the
Year 2000 project were less than $200,000. The Company did not experience any
disruption of operations from the Year 2000 threat.
LIQUIDITY AND CAPITAL RESOURCES
The Company's primary sources of capital are its cash flows from operations,
borrowings and sale of debt and equity securities. Net cash and cash equivalents
increased during 1999 by $28.4 million. Cash provided from
23
<PAGE> 24
operating activities during 1999 totaled $21.2 million. The Company completed a
Common Stock offering which netted the Company $41.1 million in November 1999.
An additional $22 million (net) was borrowed and cash capital expenditures for
the twelve-month period totaled $51.7 million. $2.3 million was paid as
dividends on preferred stock. Average debt outstanding was $96.9 million during
1999 compared to $64.8 million in 1998. At December 31, 1999, the Company had
working capital of $20.5 million.
Effective October 31, 1996, the Company entered into a Credit Facility with
Chase Manhattan Bank. Borrowings under the Credit Facility are secured by
mortgages covering substantially all of the Company's producing oil and gas
properties. The Credit Facility currently 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. The Company may borrow, pay, reborrow and
repay under the Credit Facility until October 31, 2000, on which date, the
Company must repay in full all amounts then outstanding. At December 31, 1999,
the availability on this Credit Facility was $29.9 million.
On November 27, 1996, the Company issued $24,150,000 of 10% Senior Subordinated
Notes ("10% Notes") that will mature December 15, 2001. The notes are redeemable
at the option of the Company, in whole or in part, 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 ("Series A Notes") due 2002 in a private placement for net
proceeds of $34.8 million. On September 10, 1997, pursuant to a Registration
Agreement dated July 31, 1997, the Company exchanged 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 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 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 is in compliance
with these covenants at December 31, 1999.
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 expenses was $30,899,000. Each share has
a liquidation preference of $25, 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
24
<PAGE> 25
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
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
principal amount of Debentures for each share of Preferred Stock. The Debentures
will be convertible into Common Stock of the Company on the same terms as the
Preferred Stock and will pay interest semi-annually.
In November of 1999, the Company sold 3,680,000 shares of Common Stock in a
public offering at a price to the public of $11.875 per share. Cash proceeds
received by the Company were $41.1 million net of underwriting discount and
offering costs. The proceeds from the stock offering were used to pay the
outstanding balance of the Credit Facility and to fund, together with internally
generated cash flows from operations, the remaining portion of its 1999 and part
of the 2000 capital expenditure budget.
Gross capital expenditures for 1999 totaled $68.9 million which included $24.1
million (of this amount, $14.8 million was financed by a volumetric production
payment) for the acquisition of oil and gas properties, $43.0 million for
property development and drilling activities on new and previously existing
properties and $1.8 million for acquisition of oil and gas properties not yet
evaluated. The Company's plans for 2000 include capital expenditures of
approximately $85 million, primarily in the Gulf of Mexico. Projected cash flows
from operations, cash on hand and borrowings under the Credit Facility are
anticipated to be sufficient to fund this capital budget; however, the Company
may consider alternative sources of financing. Future capital expenditure
requirements for 2000 will depend somewhat on exploration results.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to the
oil and gas operations of the Company for each of the three years in the period
ended December 31, 1999.
25
<PAGE> 26
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1999(a) 1998 1997
------- ------ ------
<S> <C> <C> <C>
Production:
Oil (MBbls) 330 310 462
Gas (MMcf) 14,606 14,036 13,114
Total production (MMcfe) 16,589 15,894 15,887
Average daily production (MMcfe) 45.5 43.5 43.5
Average sales price:
Oil (per Bbl) $ 12.16 $ 12.41 $ 18.63
Gas (per Mcf) $ 2.27 $ 2.26 $ 2.56
Total production (per Mcfe) $ 2.24 $ 2.24 $ 2.65
Average costs (per Mcfe):
Lease operating expenses (excluding severance taxes)$ .39 $ .44 $ .42
Severance taxes $ .07 $ .06 $ .09
Depletion $ .99 $ 1.19 $ 1.02
General and administrative (net of management fees) $ .28 $ .33 $ .28
</TABLE>
(a) Includes volumes of 1,300 MMcf at an average price of $2.08 per Mcf
associated with a volumetric production payment.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1999
AND 1998
OIL AND GAS REVENUES
Oil and gas revenues for 1999 were $37.1 million, a 4% increase from the 1998
amount of $35.6 million. Similarly, 1999 oil and gas production of 16,600 MMcfe
increased by 4% over the 1998 amount of 15,900 MMcfe.
Oil production increased from 310,000 barrels in 1998 to 330,000 barrels in 1999
but the average sales price declined from $12.41 in 1998 to $12.16 in 1999. As a
result, oil revenues went from $3.8 million in 1998 to $4.0 million in 1999. The
increase in oil production was primarily from Main Pass 26 and Eugene Island 335
offset by the loss of production in 1999 from the Black Bay Field, which was
sold in 1998.
Gas revenues for 1999 were $33.1 million based on sales of 14.6 Bcf at an
average sales price of $2.27 per Mcf. For 1998, gas revenues were $31.8 million
based on production of 14 Bcf sold at an average sales price of $2.26 per Mcf.
When compared to 1998, the Company in 1999 added gas production from new
discoveries at Main Pass 26 and Eugene Island 335 but has experienced reduced
production from several Shallow Miocene properties which normally have steep
decline curves. Except for the increase at Main Pass 31, which was the result of
a recompletion, other properties continue to experience normal and expected
declines.
The following table summarizes oil and gas production from the Company's major
producing properties for the years 1999 and 1998:
<TABLE>
<CAPTION>
OIL PRODUCTION GAS PRODUCTION
(Bbls) (Mcf)
------------------ -----------------------
1999 1998 1999 1998
-------- -------- ---------- ---------
<S> <C> <C> <C> <C>
Mobile Block 864 Area -- -- 5,550,700 5,355,200
Chandeleur Block 40 -- -- 804,600 2,443,400
Main Pass 163 Area -- -- 1,946,400 3,007,100
</TABLE>
26
<PAGE> 27
<TABLE>
<S> <C> <C> <C> <C>
Main Pass 26 46,700 500 823,600 --
Eugene Island 335 24,700 -- 1,089,600 --
Main Pass 31 34,300 39,400 1,148,200 1,045,300
Main Pass 164/165 -- -- -- --
North Dauphin Island Field -- -- 479,200 1,012,600
High Island Block A-494 -- -- 1,130,900 --
Escambia Minerals 144,400 152,700 257,000 269,600
Other Properties 80,300 117,100 1,375,700 902,800
------ ---------- ---------- ----------
Total 330,400 309,700 14,605,900 14,036,000
======= ========== ========== ==========
</TABLE>
LEASE OPERATING EXPENSES AND SEVERANCE TAXES
Lease operating expenses, including severance taxes, decreased from $7.8 million
in 1998 to $7.5 million in 1999 as a result of a decrease in operating expenses
in the Main Pass 163 Area and the North Dauphin Island Field as well as the sale
of the Black Bay Field in 1998. This decline was offset by the Snapper, Main
Pass 36, Main Pass 26 and Kemah properties which began operations in 1999.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization decreased due to the combined effect of
the net increase in proved reserves during 1999 (primarily in the fourth quarter
of 1999), the level of finding costs attributable to reserves added in 1999 and
the reduction of the full cost pool due to an impairment of oil and gas
properties at December 31, 1998. Total charges decreased from $19.3 million, or
$1.21 per Mcfe in 1998, to $16.7 million, or $1.01 per Mcfe in 1999.
GENERAL AND ADMINISTRATIVE
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 is
primarily due to a reduction of staff in 1999 along with an increase in overhead
allocable to employees directly engaged in the acquisition, exploration and
development of oil and gas properties in 1999.
INTEREST EXPENSE
Interest expense for 1999 and 1998 was $6.2 million and $1.9 million,
respectively. This increase is a result of a decrease in interest capitalized on
unevaluated oil and gas properties and the increase in interest rates and in
average debt outstanding in 1999 versus 1998. This average debt outstanding
increase is directly related to the Senior Subordinated Notes issued in July
1999 and the Credit Facility borrowings during the year. The Common Stock
offering completed in November 1999 reduced Credit Facility debt at the end of
1999.
INCOME TAXES
The Company's 1999 results include a deferred income tax expense of $1.4
million. The Company has evaluated the realizability of the deferred income tax
asset in light of its reserve quantity estimates, its long-
27
<PAGE> 28
term outlook for oil and gas prices and its expected level of future revenues
and expenses. The Company believes it is more likely than not, based upon this
evaluation, that it will realize the recorded deferred income tax asset.
However, there is no assurance that such asset will ultimately be realized.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1998
AND 1997
OIL AND GAS REVENUES
Oil and gas revenues for 1998 were $35.6 million, a 15% reduction from the 1997
amount of $42.1 million. On a Mcfe basis, 1998 production was the same as that
reported for 1997. Therefore, the reduction in revenues was attributable to the
15% reduction in average sales price per Mcfe.
Oil production declined from 462,000 barrels in 1997 to 310,000 barrels in 1998
and the average sales price declined from $18.63 in 1997 to $12.41 in 1998. As a
result, oil revenues declined from $8.6 million in 1997 to $3.8 million in 1998.
This reduction was attributable to reduced prices and the divestiture of the
Black Bay Complex in May 1998.
Gas revenues for 1998 were $31.8 million based on sales of 14 Bcf at an average
sales price of $2.26 per Mcf. For 1997, gas revenues were $33.5 million based on
production of 13.1 Bcf sold at an average sales price of $2.56 per Mcf.
LEASE OPERATING EXPENSES AND SEVERANCE TAXES
Lease operating expenses, including severance taxes, decreased from $8.1 million
in 1997 to $7.8 million in 1998. Separately, severance taxes declined from $1.4
million in 1997 to $0.9 million in 1998 as a result of lower production on
properties subject to severance taxes and lower oil and gas prices. Other
operating expenses increased slightly 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 partially offset by a reduction due to the sale of Black
Bay.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased as a higher rate was applied
to a relatively constant production volume. Total charges increased from $16.5
million, or $1.04 per Mcfe, in 1997 to $19.3 million, or $1.19 per Mcfe in 1998.
The increase in the noncash charge per Mcfe reflects the increase in investment
in evaluated oil and gas properties during 1998.
GENERAL AND ADMINISTRATIVE
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 is
primarily the result of the loss of Black Bay management fees, which normally
reduce general and administrative expenses, and slightly higher normal corporate
expenses.
28
<PAGE> 29
INTEREST EXPENSE
Interest expense for 1998 and 1997 was $1.9 million and $2.0 million,
respectively.
ACCELERATED VESTING AND RETIREMENT BENEFITS
In December 1998, the Company recorded a charge of $5.8 million attributable to
the accelerated vesting of the remaining performance shares previously granted
under the Company's stock option plans and of retirement benefits.
IMPAIRMENT OF OIL AND GAS PROPERTIES
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 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 (PV10). 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.
INCOME TAXES
The Company's 1998 results include 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. The Company expects to
realize this benefit for tax purposes in future years by utilizing its net
operating loss and statutory depletion carryforwards and the turn around of
temporary differences. The Company has evaluated the reliability of the deferred
income tax benefit recorded above in light of its reserve quantity estimates,
its long-term outlook for oil and gas prices and its expected level of other
future expenses. The Company believes it is more likely than not, based upon
this evaluation, that it will realize the recorded deferred income tax asset.
However, there is no assurance that such asset will ultimately be realized.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
The Company's revenues are derived from the sale of its crude oil and natural
gas production. From time to time, the Company has entered into hedging
transactions that lock in for specified periods the prices the Company will
receive for the production volumes to which the hedge relates. The hedges reduce
the Company's exposure on the hedged volumes to decreases in commodities prices
and limit the benefit the Company might otherwise have received from any
increases in commodities prices on the hedged volumes.
As of December 31, 1999, the Company had open collar contracts with third
parties whereby minimum floor prices and maximum ceiling prices are contracted
and applied to related contract volumes. These agreements in effect for 2000 are
for average gas volumes of 231,250 Mcf per month beginning in February 2000
through September 2000 at (on average) a ceiling price of $2.80 and floor price
of $2.56. The Company had no open oil hedging contracts at December 31, 1999.
<PAGE> 30
Based on projected annual sales volumes for 2000 (excluding production forecast
increases over 1999), a 10% decline in the prices the Company receives for its
crude oil and natural gas production would have an approximate $4.2 million
impact on the Company's revenues. The hypothetical impact on the decline in oil
and gas prices is net of the incremental gain that would be realized upon a
decline in prices by the oil and gas hedging contracts in place as of March 8,
2000.
30
<PAGE> 31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants 32
Consolidated Balance Sheets as of December 31, 1999 33
and 1998
Consolidated Statements of Operations for Each of the Three Years
in the Period Ended December 31, 1999 34
Consolidated Statements of Stockholders' Equity
for Each of the Three Years in the Period Ended December 31, 1999 35
Consolidated Statements of Cash Flows for Each of the Three Years
in the Period Ended December 31, 1999 36
Notes to Consolidated Financial Statements 37
</TABLE>
31
<PAGE> 32
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
32
<PAGE> 33
CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
1999 1998
--------- ---------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 34,671 $ 6,300
Accounts receivable 5,362 6,024
Other current assets 1,004 1,924
--------- ---------
Total current assets 41,037 14,248
--------- ---------
Oil and gas properties, full-cost accounting method:
Evaluated properties 511,689 444,579
Less accumulated depreciation, depletion and amortization (361,758) (345,353)
--------- ---------
149,931 99,226
Unevaluated properties excluded from amortization 44,434 42,679
--------- ---------
Total oil and gas properties 194,365 141,905
--------- ---------
Pipeline and other facilities, net 5,860 6,182
Other property and equipment, net 1,450 1,753
Deferred tax asset 14,995 16,348
Long-term gas balancing receivable 243 199
Other assets, net 1,927 1,017
--------- ---------
Total assets $ 259,877 $ 181,652
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 16,786 $ 11,257
Undistributed oil and gas revenues 2,082 1,720
Accrued net profits interest payable 1,676 129
--------- ---------
Total current liabilities 20,544 13,106
--------- ---------
Accounts payable and accrued liabilities to be refinanced -- 3,000
Long-term debt 100,250 78,250
Deferred revenue on sale of production payment 12,080 --
Accrued retirement benefits 2,107 2,323
Long-term gas balancing payable 516 489
--------- ---------
Total liabilities 135,497 97,168
--------- ---------
Stockholders' equity:
Preferred Stock, $.01 par value; 2,500,000 shares
authorized; 1,045,461 shares of Convertible
Exchangeable Preferred Stock, Series A issued
and outstanding at December 31, 1999 and
1,255,811 outstanding at December 31, 1998 with
a liquidation preference of $26,136,525 at December 31, 1999 11 13
Common Stock, $.01 par value; 20,000,000
shares authorized; 12,239,238 and 8,178,406 shares
outstanding at December 31, 1999 and 1998, respectively 122 82
Treasury stock (99,078 shares at cost) (1,183) (915)
Capital in excess of par value 149,425 109,429
Retained earnings (deficit) (23,995) (24,125)
--------- ---------
Total stockholders' equity 124,380 84,484
--------- ---------
Total liabilities and stockholders' equity $ 259,877 $ 181,652
========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
33
<PAGE> 34
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Oil and gas sales $ 37,140 $ 35,624 $ 42,130
Interest and other 1,853 2,094 1,508
-------- -------- --------
Total revenues 38,993 37,718 43,638
-------- -------- --------
Costs and expenses:
Lease operating expenses 7,536 7,817 8,123
Depreciation, depletion and amortization 16,727 19,284 16,488
General and administrative 4,575 5,285 4,433
Interest 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 35,013 83,572 31,001
-------- -------- --------
Income (loss) from operations 3,980 (45,854) 12,637
Income tax expense (benefit) 1,353 (15,100) 4,200
-------- -------- --------
Net income (loss) 2,627 (30,754) 8,437
Preferred stock dividends 2,497 2,779 2,795
-------- -------- --------
Net income (loss) available to common shares $ 130 $(33,533) $ 5,642
======== ======== ========
Net income (loss) per common share:
Basic $ .01 $ (4.17) $ .91
======== ======== ========
Diluted $ .01 $ (4.17) $ .88
======== ======== ========
Shares used in computing net income (loss) per common share:
Basic 8,976 8,034 6,194
======== ======== ========
Diluted 9,075 8,034 6,422
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
34
<PAGE> 35
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 (loss) -- -- -- -- -- 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)
==== ==== ========= ======= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
35
<PAGE> 36
CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss) $ 2,627 $(30,754) $ 8,437
Adjustments to reconcile net income to
cash provided by operating activities:
Depreciation, depletion and amortization 17,232 19,791 16,924
Impairment of oil and gas properties -- 43,500 --
Amortization of deferred costs 707 619 467
Amortization of deferred production payment revenue (2,710) -- --
Deferred income tax expense (benefit) 1,353 (15,100) 4,200
Noncash compensation related to compensation plans 275 7,583 1,224
Changes in current assets and liabilities:
Accounts receivable 662 6,144 493
Other current assets 920 (1,201) (207)
Current liabilities 1,981 (876) (3,809)
Change in gas balancing receivable (44) 43 418
Change in gas balancing payable 27 85 14
Change in other long-term liabilities (216) -- 249
Change in other assets, net (1,617) (129) (1,073)
-------- -------- --------
Cash provided (used) by operating activities 21,197 29,705 27,337
-------- -------- --------
Cash flows from investing activities:
Capital expenditures (51,709) (63,501) (85,999)
Cash proceeds from sale of mineral interests -- 9,909 4,450
-------- -------- --------
Cash provided (used) by investing activities (51,709) (53,592) (81,549)
-------- -------- --------
Cash flows from financing activities:
Equity issued related to employee stock plans 68 414 90
Purchase of treasury shares (268) (915) --
Payments on debt (42,500) -- (49,200)
Increase in debt 64,500 18,000 85,200
Restricted stock plan (1,615) (130) (422)
Sale of common stock 41,031 -- 29,267
Cash dividends on preferred stock (2,333) (2,779) (2,795)
-------- -------- --------
Cash provided (used) by financing activities 58,883 14,590 62,140
-------- -------- --------
Net increase (decrease) in cash and cash equivalents 28,371 (9,297) 7,928
Cash and cash equivalents:
Balance, beginning of period 6,300 15,597 7,669
-------- -------- --------
Balance, end of period $ 34,671 $ 6,300 $ 15,597
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
36
<PAGE> 37
CALLON PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 Statement will create volatility in equity through
other comprehensive income due to the mark-to-market of hedging contracts (see
Note 6); however, the Company believes these instruments will be treated as
hedges under FAS 133 and does not anticipate that FAS 133 will have a material
impact on the Company's Statement of Operations.
37
<PAGE> 38
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, estimated future
abandonment costs on the Company's oil and gas properties, included as future
development costs, were approximately $15.8 million.
Depreciation of other property and equipment is provided using the straight-line
method over estimated lives of three to 20 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.
38
<PAGE> 39
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.
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 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.
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.
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 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 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 common share.
39
<PAGE> 40
A computation of the basic and diluted per share computation is as follows (in
thousands, except per share amounts):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
(a) Net income (loss) available for common stock $ 130 $(33,533) $ 5,642
(b) Weighted average shares outstanding 8,976 8,034 6,194
(c) Dilutive impact of stock options 99 -- 228
(d) Total diluted shares 9,075 8,034 6,422
Stock options excluded due to antidilutive impact -- 163 --
Basic earnings (loss) per share (a/b) $ .01 $ (4.17) $ .91
Diluted earnings (loss) per share (a/d) $ .01 $ (4.17) $ .88
</TABLE>
FAIR VALUE OF FINANCIAL INSTRUMENTS
Fair value of cash, cash equivalents, accounts receivable, accounts payable and
long-term debt approximates book value at December 31, 1999 and 1998. Fair value
of long-term debt (specifically, the 10%, the 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 required in 1999 and 1998.
Accordingly, the Company has recorded a deferred tax asset at December 31, 1999
and 1998 as follows:
40
<PAGE> 41
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1999 1998
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Federal net operating loss carryforwards $ 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.
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>
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.
41
<PAGE> 42
5. LONG-TERM DEBT
Long-term debt consisted of the following at:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1999 1998
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Credit Facility $ 100 $ 18,100
10% Senior Subordinated Notes 24,150 24,150
10.125% Senior Subordinated Notes 36,000 36,000
10.25% Senior Subordinated Notes 40,000 --
-------- --------
100,250 78,250
Less: current portion -- --
-------- --------
$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, the
interest rate is equal to the lender's prime rate plus 0.50%. The Company, at
its option, may fix the interest rate on all or a portion of the outstanding
principal balance 2% above a defined "Eurodollar" rate for periods up to six
months. The weighted average interest rate for the Credit Facility debt
outstanding at December 31, 1999 and 1998 was 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 until October 31, 2000, on which
date, the Company must repay in full all amounts then outstanding. The Company
expects various terms to be revised, including the extension of the maturity
date, when the Credit Facility is renegotiated in 2000.
On November 27, 1996, the Company issued $24,150,000 of 10% Senior Subordinated
Notes that will mature December 15, 2001. 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 September 15, 2002. 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
42
<PAGE> 43
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 is in compliance
with these covenants at December 31, 1999.
6. HEDGING CONTRACTS
The Company periodically uses derivative financial instruments to manage oil and
gas price risk. Settlements of gains and losses on commodity price 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 contract are deferred and
recognized in revenue when the oil and gas production is sold. In 1999,
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 1998 and 1997 as a result of such agreements.
As of December 31, 1999, the Company had open collar contracts with third
parties whereby minimum floor prices and maximum ceiling prices are contracted
and applied to related contract volumes. These agreements in effect for 2000 are
for average gas volumes of 231,250 Mcf per month beginning in February 2000
through September 2000 at (on average) a ceiling price of $2.80 and floor price
of $2.56. The Company had no open oil hedging contracts at December 31, 1999.
7. COMMITMENTS AND CONTINGENCIES
As described in Note 9, abandonment trusts (the "Trusts") have been established
for future abandonment obligations of those oil and gas properties of the
Company burdened by a net profits interest. The management of the Company
believes the Trusts will be sufficient to offset those future abandonment
liabilities; however, the Company is responsible for any abandonment expenses in
excess of the Trusts' balances. As of December 31, 1999 total estimated site
restoration; dismantlement and abandonment costs were approximately $5,690,000,
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.
43
<PAGE> 44
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>
YEARS ENDED DECEMBER 31,
---------------------------------------
1999 1998 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance $ 444,579 $ 398,046 $ 322,970
Property acquisition costs 24,153 9,464 51,751
Exploration costs 37,427 42,617 13,620
Development costs 5,530 4,361 14,155
Sale of mineral interests -- (9,909) (4,450)
--------- --------- ---------
End of period balance $ 511,689 $ 444,579 $ 398,046
========= ========= =========
Unevaluated Properties (excluded from the
full-cost pool) -
Beginning of period balance $ 42,679 $ 35,339 $ 26,235
Additions 4,890 11,156 16,924
Capitalized interest and general and
administrative costs 7,120 8,955 5,163
Transfers to evaluated (10,255) (12,771) (12,983)
--------- --------- ---------
End of period balance $ 44,434 $ 42,679 $ 35,339
========= ========= =========
Accumulated depreciation, depletion
and amortization
Beginning of period balance $ 345,353 $ 282,891 $ 266,716
Provision charged to expense 16,405 18,962 16,175
Impairment of oil and gas properties -- 43,500 --
--------- --------- ---------
End of period balance $ 361,758 $ 345,353 $ 282,891
========= ========= =========
</TABLE>
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.
Depletion 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.
IMPAIRMENT OF OIL AND GAS PROPERTIES-1998
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 (PV10). If capitalized costs exceed this
limit, the excess is charged to expense. During
44
<PAGE> 45
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, all of which will be available to the Company to
pay its portion, as working interest owner, of the restoration, dismantlement
and abandonment costs discussed at Note 7.
At the time of acquisition of properties by the Company, the property owners
estimated the future costs to be incurred for site restoration, dismantlement
and abandonment, net of salvage value. A portion of the amounts necessary to pay
such estimated costs was deposited in the Trusts upon acquisition of the
properties, and the remainder is deposited from time to time out of the proceeds
from production. The determination of the amount deposited upon the acquisition
of the properties and the amount to be deposited as proceeds from production was
based on numerous factors, including the estimated reserves of the properties.
The amounts deposited in the Trusts upon acquisition of the properties were
capitalized by the Company as oil and gas properties.
As operator, the Company receives all of the revenues and incurs all of the
production costs for the purchased oil and gas properties but retains only that
portion applicable to its net ownership share. As a result, the payables and
receivables associated with operating the properties included in the Company's
Consolidated Balance Sheets include both the Company's and all other outside
owners' shares. However, revenues and production costs associated with the
acquired properties reflected in the accompanying Consolidated Statements of
Operations represent only the Company's share, after reduction for the NPI.
45
<PAGE> 46
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, including Company discretionary contributions,
immediately upon participation in the Savings and Protection Plan. The
total amounts contributed by the Company, including the value of the
common stock contributed, were $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 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. All of such options are to be 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.
46
<PAGE> 47
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 No. 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>
1999 1998 1997
------- -------- ------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <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 .01 (4.17) .91
Pro Forma (.14) (4.28) .80
Diluted earnings (loss) per share: As Reported .01 (4.17) .88
Pro Forma (.14) (4.28) .77
</TABLE>
Because the FAS 123 method of accounting does not apply 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 AVG WTD AVG WTD 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 option 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.
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 6.3% 5.1% 6.8%
Expected life (years) 7.0 7.0 4.0
Expected volatility 46.0% 28.8% 41.1%
Expected dividends -- -- --
</TABLE>
47
<PAGE> 48
The Company awarded 225,000 performance shares under the 1996 Plan to the
Company's Executive officers on August 23, 1996. All of the performance shares
granted were scheduled to vest in whole on January 1, 2001. 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 $3,469,000 which represents the future unamortized expense related to
unvested shares at the date the acceleration of vesting occurred, was expensed
in 1998.
In addition, the Company recorded a provision of approximately $2.3 million for
retirement benefits approved 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.
48
<PAGE> 49
In a December 1998 private transaction, a preferred stockholder elected to
convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's
Common Stock. In 1999 certain other preferred stockholders, through private
transactions, agreed to convert 210,350 shares of Preferred Stock into 502,637
shares of the Company's Common Stock under similar terms. Any noncash premium
negotiated in excess of the conversion rate was recorded as additional preferred
stock dividends and excluded from the Consolidated Statements of Cash Flows.
In November of 1999, the Company sold 3,680,000 shares of Common Stock in a
public offering at a price to the public of $11.875 per share. Cash proceeds
received by the Company were $41.1 million net of underwriting discount and
offering costs.
12. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)
The Company's proved oil and gas reserves at December 31, 1998, 1997 and 1996
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions.
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.
49
<PAGE> 50
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>
50
<PAGE> 51
STANDARDIZED MEASURE
The following tables present the Company's standardized measure of discounted
future net cash flows and changes therein relating to proved oil and gas
reserves and were computed using reserve valuations based on regulations
prescribed by the SEC. These regulations provide that the oil, condensate and
gas price structure utilized to project future net cash flows reflects current
prices at each date presented and have been escalated only when known and
determinable price changes are provided by contract and law. Future production,
development and net abandonment costs are based on current costs without
escalation. The resulting net future cash flows have been discounted to their
present values based on a 10% annual discount factor.
STANDARDIZED MEASURE
<TABLE>
<CAPTION>
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>
51
<PAGE> 52
13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- --------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
1999
- ----
<S> <C> <C> <C> <C>
Total revenues $ 8,374 $ 9,031 $ 10,584 $ 11,004
Total costs and expenses 7,659 8,690 8,986 9,678
Income taxes expense (benefit) 243 116 543 451
Net income (loss) 472 225 1,055 875
Net income (loss) per share-basic (.04) (.04) .06 .03
Net income (loss) per share-diluted (.04) (.04) .06 .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 taxes expense (benefit) 621 380 487 (16,588)
Net income (loss) 1,207 747 933 (33,641)
Net income (loss) per share-basic .06 .01 .03 (4.27)
Net income (loss) per share-diluted .06 .01 .03 (4.27)
</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.
52
<PAGE> 53
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III.
ITEMS 10, 11, 12 &13
For information concerning Item 10 - Directors and Executive Officers of the
Registrant, Item 11 - Executive Compensation, Item 12 - Security Ownership of
Certain Beneficial Owners and Management and Item 13 - Certain Relationships and
Related Transactions, see the definitive Proxy Statement of Callon Petroleum
Company relating to the Annual Meeting of Stockholders on May 9, 2000 which will
be filed with the Securities and Exchange Commission and is incorporated herein
by reference.
53
<PAGE> 54
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. The following is an index to the financial statements and financial
statement schedules that are filed as part of this Form 10-K on pages 32 through
52.
Report of Independent Public Accountants
Consolidated Balance Sheets as of the Years Ended December 31, 1999 and
1998
Consolidated Statements of Operations for the Three Years in the Period
Ended December 31, 1999
Consolidated Statements of Stockholders' Equity for the Three Years in the
Period Ended December 31, 1999
Consolidated Statements of Cash Flows for the Three Years in the Period
Ended December 31, 1999
Notes to Consolidated Financial Statements
(a) 2. Schedules other than those listed above are omitted because they are not
required, not applicable or the required information is included in the
financial statements or notes thereto.
(a) 3. Exhibits:
<TABLE>
<S> <C>
2. Plan of acquisition, reorganization, arrangement, liquidation or
succession*
3. Articles of Incorporation and Bylaws
3.1 Certificate of Incorporation of the Company, as amended
(incorporated by reference from Exhibit 3.1 of the Company's
Registration Statement on Form S-4, filed August 4, 1994, Reg.
No. 33-82408)
3.2 Certificate of Merger of Callon Consolidated Partners, L. P.
with and into the Company dated September 16, 1994 (incorporated
by reference from Exhibit 3.2 of the Company's Report on Form
10-K for the fiscal year ended December 31, 1994)
3.3 Bylaws of the Company (incorporated by reference from Exhibit
3.2 of the Company's Registration Statement on Form S-4, filed
August 4, 1994, Reg. No. 33-82408)
4. Instruments defining the rights of security holders, including
indentures
4.1 Specimen Common Stock Certificate (incorporated by reference
from Exhibit 4.1 of the Company's Registration Statement on Form
S-4, filed August 4, 1994, Reg. No. 33-82408)
</TABLE>
54
<PAGE> 55
<TABLE>
<S> <C>
4.2 Specimen Preferred Stock Certificate (incorporated by reference
from Exhibit 4.2 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)
4.3 Designation for Convertible, Exchangeable Preferred Stock,
Series A (incorporated by reference from Exhibit 4.3 of the
Company's Registration Statement on Form S-1, filed November 13,
1995, Reg. No. 33-96700)
4.4 Indenture for Convertible Debentures (incorporated by reference
from Exhibit 4.4 of the Company's Registration Statement on Form
S-1, filed November 13, 1995, Reg. No. 33-96700)
4.5 Certificate of Correction on Designation of Series A Preferred
Stock (incorporated by reference from Exhibit 4.4 of the
Company's Registration Statement on Form S-1, filed November 22,
1996, Reg. No. 333-15501)
4.6 Form of Note Indenture for the Company's 10% Senior Subordinated
Notes due 2001 (incorporated by reference from Exhibit 4.6 of
the Company's Registration Statement on Form S-1, filed November
22, 1996, Reg. No. 333-15501)
4.7 Form of Note Indenture for the Company's 10.25% Senior
Subordinated Notes due 2004 (incorporated by reference from
Exhibit 4.10 of the Company's Registration Statement on Form
S-2, filed June 25, 1999, Reg. No. 333-80579)
9. Voting trust agreement
9.1 Stockholders' Agreement dated September 16, 1994 among the
Company, the Callon Stockholders and NOCO Enterprises, L. P.
(incorporated by reference from Exhibit 9.1 of the Company's
Registration Statement on Form 8-B filed October 3, 1994)
9.2 Addendum to Stockholders' Agreement dated August 11, 1997
between Fred. Olsen Energy ASA, the Company and other
stockholders of the Company (incorporated by reference from
Exhibit 9.2 of the Company's Registration Statement on Form 8-A
filed July 12, 1999)
9.3 Addendum to Stockholders' Agreement dated February 11, 1998
between Fred. Olsen Limited, the Company and other stockholders
of the Company (incorporated by reference from Exhibit 9.3 of
the Company's Registration Statement on Form 8-A filed July 12,
1999)
10. Material contracts
10.1 Registration Rights Agreement dated September 16, 1994 between
the Company and NOCO Enterprises, L. P. (incorporated by
reference from Exhibit 10.2 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
</TABLE>
55
<PAGE> 56
<TABLE>
<S> <C>
10.2 Registration Rights Agreement dated September 16, 1994 between
the Company and Callon Stockholders (incorporated by reference
from Exhibit 10.3 of the Company's Registration Statement on
Form 8-B filed October 3, 1994)
10.3 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated
by reference from Exhibit 10.5 of the Company's Registration
Statement on Form 8-B filed October 3, 1994)
10.4 Credit Agreement dated October 14, 1994 by and between the
Company, Callon Petroleum Operating Company and Internationale
Nederlanden (U.S.) Capital Corporation (incorporated by
reference from Exhibit 99.1 of the Company's Report on Form 10-Q
for the quarter ended September 30, 1994)
10.5 Third Amendment dated February 22, 1996, to Credit Agreement by
and among Callon Petroleum Operating Company, Callon Petroleum
Company and Internationale Nederlanden (U. S.) Capital
Corporation (incorporated by reference from Exhibit 10.9 of the
Company's Form 10-K for the fiscal year ended December 31, 1995)
10.6 Consulting Agreement between the Company and John S. Callon
dated June 19, 1996 (incorporated by reference from Exhibit
10.10 of the Company's Registration Statement on Form S-1, filed
November 5, 1996, Reg. No. 333-15501)
10.7 Employment Agreement effective September 1, 1996, between the
Company and Fred L. Callon (incorporated by reference from
Exhibit 10.4 of the Company's Registration Statement on Form
S-1, filed November 14, 1996, Reg. No. 333-15501)
10.8 Employment Agreement effective September 1, 1996, between the
Company and Dennis W. Christian (incorporated by reference from
Exhibit 10.7 of the Company's Registration Statement on Form
S-1, filed November 14, 1996, Reg. No. 333-15501)
10.9 Employment Agreement effective September 1, 1996, between the
Company and John S. Weatherly (incorporated by reference from
Exhibit 10.8 of the Company's Registration Statement on Form
S-1, filed November 14, 1996, Reg. No. 333-15501)
10.10 Callon Petroleum Company Amended 1996 Stock Incentive Plan
(incorporated by reference from Exhibit 4.4 of the
Post-Effective Amendment No. 1 to the Company's Registration
Statement on Form S-8, filed February 5, 1999, Reg. No.
333-29537)
10.11 Purchase and Sale Agreement between Callon Petroleum Operating
Company and Murphy Exploration Company, dated May 26, 1999
(incorporated by reference from Exhibit 10.11 on Form S-2, filed
June 14, 1999, Reg. No. 333-80579)
11. Statement re computation of per sharing earnings*
12. Statements re computation of ratios*
13. Annual Report to security holders, Form 10-Q or quarterly
reports*
</TABLE>
56
<PAGE> 57
<TABLE>
<S> <C>
16. Letter re change in certifying accountant*
18. Letter re change in accounting principles*
21. Subsidiaries of the Company
21.1 Subsidiaries of the Company (incorporated by reference from
Exhibit 21.1 of the Company's Registration Statement on Form 8-B
filed October 3, 1994)
22. Published report regarding matters submitted to vote of security
holders*
23. Consents of experts and counsel
23.1 Consent of Arthur Andersen LLP
24. Power of attorney*
27. Financial data schedule
A financial data schedule for the year ended December 31, 1999
(EX-27) was filed electronically along with the Form 10-K.
99. Additional Exhibits*
</TABLE>
- -----------------------------
*Inapplicable to this filing.
(b) Reports on Form 8-K.
The Company filed a Report on Form 8-K on November 4, 1999 under "Item 5 - Other
Events."
57
<PAGE> 58
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the registrant and
in the capacities and on the dates indicated.
CALLON PETROLEUM COMPANY
<TABLE>
<S> <C>
Date: March 23, 2000 /s/ FRED L.CALLON
------------------------------------------------------
Fred L. Callon (principal executive officer, director)
Date: March 23, 2000 /s/ JOHN S. WEATHERLY
------------------------------------------------------
John S. Weatherly (principal financial officer)
Date: March 23, 2000 /s/ JAMES O. BASSI
------------------------------------------------------
James O. Bassi (principal accounting officer)
Date: March 23, 2000 /s/ JOHN S. CALLON
------------------------------------------------------
John S. Callon (director)
Date: March 23, 2000 /s/ DENNIS W. CHRISTIAN
------------------------------------------------------
Dennis W. Christian (director)
Date: March 23, 2000 /s/ B. F. WEATHERLY
------------------------------------------------------
B. F. Weatherly (director)
Date: March 23, 2000 /s/ JOHN C. WALLACE
------------------------------------------------------
John C. Wallace (director)
</TABLE>
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CALLON PETROLEUM COMPANY
Date: March 23, 2000 By: /s/ JOHN S. WEATHERLY
--------------------------------------------
John S. Weatherly, Senior Vice President and
Chief Financial Officer
58
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report dated February 16, 2000, included in this Form 10-K,
into Callon Petroleum Company's previously filed Registration Statements on
Forms S-8 (File Nos.33-90410, 333-29537 and 333-29529).
Arthur Andersen LLP
March 24, 2000
New Orleans, Louisiana
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE CONSOLIDATED FINANCIAL STATEMENTS OF CALLON PETROLEUM COMPANY FOR THE
PERIOD ENDING DECEMBER 31, 1999 WHICH ARE PRESENTED IN ITS ANNUAL REPORT ON FORM
10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 34,671
<SECURITIES> 0
<RECEIVABLES> 5,362
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 41,037
<PP&E> 556,123
<DEPRECIATION> 361,758
<TOTAL-ASSETS> 259,877
<CURRENT-LIABILITIES> 20,544
<BONDS> 0
0
11
<COMMON> 122
<OTHER-SE> 124,247
<TOTAL-LIABILITY-AND-EQUITY> 259,877
<SALES> 37,140
<TOTAL-REVENUES> 38,993
<CGS> 0
<TOTAL-COSTS> 28,838
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 6,175
<INCOME-PRETAX> 3,980
<INCOME-TAX> 1,353
<INCOME-CONTINUING> 2,627
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,627
<EPS-BASIC> .01
<EPS-DILUTED> .01
</TABLE>
